44746 Federal Register / Vol. 83, No. 170 / Friday, August 31, 2018 / Proposed Rules 

1Comments submitted on the proposed repeal 

will be considered in the promulgation of this 

rulemaking so there is no need to resubmit 

comments that have already been timely submitted. 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 51, 52, and 60 

[EPA–HQ–OAR–2017–0355; FRL–9982–89– 

OAR] 

RIN 2060–AT67 

Emission Guidelines for Greenhouse 

Gas Emissions From Existing Electric 

Utility Generating Units; Revisions to 

Emission Guideline Implementing 

Regulations; Revisions to New Source 

Review Program 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: The Environmental Protection 

Agency (EPA) is proposing three 

distinct actions, including Emission 

Guidelines for Greenhouse Gas 

Emissions from Existing Electric Utility 

Generating Units (EGUs). First, EPA is 

proposing to replace the Clean Power 

Plan (CPP) with revised emissions 

guidelines (the Affordable Clean Energy 

(ACE) rule) that inform the 

development, submittal, and 

implementation of state plans to reduce 

greenhouse gas (GHG) emission from 

certain EGUs. In the proposed emissions 

guidelines, consistent with the 

interpretation described in the proposed 

repeal of the CPP, the Agency is 

proposing to determine that heat rate 

improvement (HRI) measures are the 

best system of emission reduction 

(BSER) for existing coal-fired EGUs. 

Second, EPA is proposing new 

regulations that provide direction to 

both EPA and the states on the 

implementation of emission guidelines. 

The new proposed implementing 

regulations would apply to this action 

and any future emission guideline 

issued under section 111(d) of the Clean 

Air Act (CAA). Third, the Agency is 

proposing revisions to the New Source 

Review (NSR) program that will help 

prevent NSR from being a barrier to the 

implementation of efficiency projects at 

EGUs. 

DATES: 

Comments. Comments must be 

received on or before October 30, 2018. 

Under the Paperwork Reduction Act 

(PRA), comments on the information 

collection provisions are best assured of 

consideration if the Office of 

Management and Budget (OMB) 

receives a copy of your comments on or 

before October 1, 2018. 

Public hearing: EPA is planning to 

hold at least one public hearing in 

response to this proposed action. 

Information about the hearing, 

including location, date, and time, along 

with instructions on how to register to 

speak at the hearing, will be published 

in a second Federal Register document. 

ADDRESSES: Comments. Submit your 

comments, identified by Docket ID No. 

EPA–HQ–OAR–2017–0355, at https://

www.regulations.gov. Follow the online 

instructions for submitting comments. 

Once submitted, comments cannot be 

edited or removed from Regulations.gov. 

See SUPPLEMENTARY INFORMATION for 

detail about how EPA treats submitted 

comments. Regulations.gov is our 

preferred method of receiving 

comments.1 However, other submission 

methods are accepted: 

• Email: a-and-r-docket@epa.gov. 

Include Docket ID No. EPA–HQ–OAR– 

2017–0355 in the subject line of the 

message. 

• Fax: (202) 566–9744. Attention 

Docket ID No. EPA–HQ–OAR–2017– 

0355. 

• Mail: To ship or send mail via the 

United States Postal Service, use the 

following address: U.S. Environmental 

Protection Agency, EPA Docket Center, 

Docket ID No. EPA–HQ–OAR–2017– 

0355, Mail Code 28221T, 1200 

Pennsylvania Avenue NW, Washington, 

DC 20460. 

• Hand/Courier Delivery: Use the 

following Docket Center address if you 

are using express mail, commercial 

delivery, hand delivery, or courier: EPA 

Docket Center, EPA WJC West Building, 

Room 3334, 1301 Constitution Avenue 

NW, Washington, DC 20004. Delivery 

verification signatures will be available 

only during regular business hours. 

FOR FURTHER INFORMATION CONTACT: For 

questions about this proposed action, 

contact Mr. Nicholas Swanson, Sector 

Policies and Programs Division (Mail 

Code D205–01), Office of Air Quality 

Planning and Standards, U.S. 

Environmental Protection Agency, 

Research Triangle Park, North Carolina 

27711; telephone number: (919) 541– 

4080; fax number: (919) 541–4991; and 

email address: swanson.nicholas@

epa.gov. 

SUPPLEMENTARY INFORMATION: 

Docket. EPA has established a docket 

for this rulemaking under Docket ID No. 

EPA–HQ–OAR–2017–0355. All 

documents in the docket are listed in 

Regulations.gov. Although listed, some 

information is not publicly available, 

e.g., confidential business information 

(CBI) or other information whose 

disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, is not placed on 

the internet and will be publicly 

available only in hard copy. Publicly 

available docket materials are available 

either electronically in Regulations.gov 

or in hard copy at the EPA Docket 

Center, Room 3334, EPA WJC West 

Building, 1301 Constitution Avenue 

NW, Washington, DC. The Public 

Reading Room is open from 8:30 a.m. to 

4:30 p.m., Monday through Friday, 

excluding legal holidays. The telephone 

number for the Public Reading Room is 

(202) 566–1744, and the telephone 

number for the EPA Docket Center is 

(202) 566–1742. 

Instructions: Direct your comments to 

Docket ID No. EPA–HQ–OAR–2017– 

0355. EPA’s policy is that all comments 

received will be included in the public 

docket without change and may be 

made available online at https://

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be CBI or other information 

whose disclosure is restricted by statute. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through https://

www.regulations.gov or email. This type 

of information should be submitted by 

mail as discussed below. 

EPA may publish any comment 

received to its public docket. 

Multimedia submissions (audio, video, 

etc.) must be accompanied by a written 

comment. The written comment is 

considered the official comment and 

should include discussion of all points 

you wish to make. EPA will generally 

not consider comments or comment 

contents located outside of the primary 

submission (i.e., on the Web, cloud, or 

other file sharing system). For 

additional submission methods, the full 

EPA public comment policy, 

information about CBI or multimedia 

submissions, and general guidance on 

making effective comments, please visit 

https://www.epa.gov/dockets/ 

commenting-epa-dockets. 

The https://www.regulations.gov 

website allows you to submit your 

comments anonymously, which means 

EPA will not know your identity or 

contact information unless you provide 

it in the body of your comment. If you 

send an email comment directly to EPA 

without going through https://

www.regulations.gov, your email 

address will be automatically captured 

and included as part of the comment 

that is placed in the public docket and 

made available on the internet. If you 

submit an electronic comment, EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 


daltland on DSKBBV9HB2PROD with PROPOSALS2
Federal Register / Vol. 83, No. 170 / Friday, August 31, 2018 / Proposed Rules 44747 

digital storage media you submit. If EPA 

cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, EPA may not be 

able to consider your comment. 

Electronic files should not include 

special characters or any form of 

encryption and be free of any defects or 

viruses. For additional information 

about EPA’s public docket, visit the EPA 

Docket Center homepage at https://

www.epa.gov/dockets. 

Throughout this proposal, EPA is 

soliciting comment on numerous 

aspects of the proposed rule. EPA has 

indexed each comment solicitation with 

an alpha-numeric identifier (e.g., ‘‘C–1’’, 

‘‘C–2’’, ‘‘C–3’’, . . .). EPA included 

similar identifiers in the advance notice 

of proposed rulemaking (ANPRM) and 

asked commenters to identify the main 

topic area that corresponded with their 

comment. In this proposal, we are 

modifying this approach to include a 

unique identifier for each individual 

comment solicitation to provide a 

consistent framework for effective and 

efficient provision of comments. 

Accordingly, we ask that commenters 

include the corresponding identifier 

when providing comments relevant to 

that comment solicitation. We ask that 

commenters include the identifier in 

either a heading, or within the text of 

each comment (e.g., ‘‘In response to 

solicitation of comment C–1, . . .’’) to 

make clear which comment solicitation 

is being addressed. We emphasize that 

we are not limiting comment to these 

identified areas and encourage 

provision of any other comments 

relevant to this proposal. 

Submitting CBI. Do not submit 

information containing CBI to EPA 

through https://www.regulations.gov or 

email. Clearly mark the part or all of the 

information that you claim to be CBI. 

For CBI information on any digital 

storage media that you mail to EPA, 

mark the outside of the digital storage 

media as CBI and then identify 

electronically within the digital storage 

media the specific information that is 

claimed as CBI. In addition to one 

complete version of the comments that 

includes information claimed as CBI, 

you must submit a copy of the 

comments that does not contain the 

information claimed as CBI directly to 

the public docket through the 

procedures outlined in Instructions 

above. If you submit any digital storage 

media that does not contain CBI, mark 

the outside of the digital storage media 

clearly that it does not contain CBI. 

Information not marked as CBI will be 

included in the public docket and the 

EPA’s electronic public docket without 

prior notice. Information marked as CBI 

will not be disclosed except in 

accordance with procedures set forth in 

40 Code of Federal Regulations (CFR) 

part 2. Send or deliver information 

identified as CBI only to the following 

address: OAQPS Document Control 

Officer (C404–02), OAQPS, U.S. 

Environmental Protection Agency, 

Research Triangle Park, North Carolina 

27711, Attention Docket ID No. EPA– 

HQ–OAR–2017–0355. 

Preamble acronyms and 

abbreviations. We use multiple 

acronyms and terms in this preamble. 

While this list may not be exhaustive, to 

ease the reading of this preamble and for 

reference purposes, EPA defines the 

following terms and acronyms here: 

ACE Affordable Clean Energy Rule 

AEO Annual Energy Outlook 

ANPRM Advance Notice of Proposed 

Rulemaking 

BACT Best Available Control Technology 

BSER Best System of Emission Reduction 

Btu British Thermal Unit 

CAA Clean Air Act 

CBI Confidential Business Information 

CCS Carbon Capture and Storage (or 

Sequestration) 

CFR Code of Federal Regulation 

CO2 Carbon Dioxide 

CPP Clean Power Plan 

EGU Electric Utility Generating Unit 

EIA Energy Information Administration 

EPA Environmental Protection Agency 

FIP Federal Implementation Plan 

FR Federal Register 

GHG Greenhouse Gas 

HRI Heat Rate Improvement 

IGCC Integrated Gasification Combined 

Cycle 

kW Kilowatt 

kWh Kilowatt-hour 

MW Megawatt 

MWh Megawatt-hour 

NAAQS National Ambient Air Quality 

Standards 

NGCC Natural Gas Combined Cycle 

NOX Nitrogen Oxides 

NSPS New Source Performance Standards 

NSR New Source Review 

OMB Office of Management and Budget 

PM2.5 Fine Particulate Matter 

PRA Paperwork Reduction Act 

PSD Prevention of Significant Deterioration 

RIA Regulatory Impact Analysis 

RTC Response to Comments 

SIP State Implementation Plan 

SO2 Sulfur Dioxide 

UMRA Unfunded Mandates Reform Act of 

1995 

U.S. United States 

VFD Variable Frequency Drive 

Organization of this document. The 

information in this preamble is 

organized as follows: 

I. General Information 

A. Executive Summary 

B. Where can I get a copy of this document 

and other related information? 

II. Background 

A. Regulatory and Judicial History of GHG 

Requirements for EGUs 

B. Executive Order 13783 and EPA’s 

Review of the CPP 

C. Industry Trends 

III. Legal Authority 

A. Authority to Revisit Existing 

Regulations 

B. Authority to Regulate EGUs 

C. Legal Authority for Determination of the 

BSER 

IV. Affected Sources 

V. Determination of the BSER 

A. Identification of the BSER 

B. HRIs for Steam-Generating EGUs 

C. HRI for Natural Gas-fired Stationary 

Combustion Turbines 

D. Other Considered Systems of GHG 

Emission Reductions 

VI. State Plan Development 

A. Establishing Standards of Performance 

B. Flexibilities for States and Sources 

C. Submission of State Plans 

VII. Proposed New Implementing Regulations 

for Section 111(d) Emission Guidelines 

A. Changes to the Definition of ‘‘Emission 

Guideline’’ 

B. Updates to Timing Requirements 

C. Compliance Deadlines 

D. Completeness Criteria 

E. Standard of Performance 

F. Variance 

VIII. New Source Review Permitting of HRIs 

A. What is New Source Review? 

B. Interaction of NSR and the ACE Rule 

C. ANPRM Solicitation and Comments 

Received 

D. Proposing NSR Changes for Improved 

ACE Implementation 

IX. Impacts 

A. What are the air impacts? 

B. What are the energy impacts? 

C. What are the compliance costs? 

D. What are the economic and employment 

impacts? 

E. What are the forgone benefits of the 

proposed action? 

X. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

B. Executive Order 13771: Reducing 

Regulation and Controlling Regulatory 

Costs 

C. Paperwork Reduction Act (PRA) 

D. Regulatory Flexibility Act (RFA) 

E. Unfunded Mandates Reform Act 

(UMRA) 

F. Executive Order 13132: Federalism 

G. Executive Order 13175: Consultation 

and Coordination with Indian Tribal 

Governments 

H. Executive Order 13045: Protection of 

Children from Environmental Health 

Risks and Safety Risks 

I. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

J. National Technology Transfer and 

Advancement Act (NTTAA) 

K. Executive Order 12898: Federal Actions 

to Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

XI. Statutory Authority 


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44748 Federal Register / Vol. 83, No. 170 / Friday, August 31, 2018 / Proposed Rules 

2The accompanying RIA focuses on presenting 

the difference between the CPP and the concepts in 

ACE, but also includes a scenario with no CPP, 

providing sufficient information to understand the 

impact of a full repeal of the CPP, a two-step 

approach in which the CPP is repealed and then an 

alternative BSER is put in place or a case in which 

the Agency revises the BSER promulgated in the 

CPP. 

I. General Information 

A. Executive Summary 

EPA is proposing the Affordable 

Clean Energy (ACE) rule as a 

replacement to the CPP (promulgated on 

October 23, 2015, 80 FR 64662), which 

sets GHG emission guidelines for 

existing EGUs. This proposal relies in 

part on the legal analysis presented in 

the CPP repeal that was proposed on 

October 16, 2017, 82 FR 48035. In the 

proposed repeal, EPA asserted that the 

BSER in the CPP exceeded EPA’s 

authority because it established the 

BSER using measures that applied to the 

power sector as whole, rather than 

measures that apply at and to, and can 

be carried out at the level of, individual 

facilities. This proposed action aligns 

with EPA’s statutory authority and 

obligation because, as EPA has done in 

the dozens of NSPSs issued to date, the 

BSER is to be determined by evaluating 

technologies or systems of emission 

reduction that are applicable to, at, and 

on the premises of the facility for an 

affected source. This proposal will 

ensure that coal-fired power plants (the 

most carbon dioxide (CO2) intensive 

portion of the electricity generating 

fleet) address their contribution to 

climate change by reducing their CO2

intensity (i.e., the amount of CO2 they 

emit per unit of electricity generated). 

Accordingly, the proposed ACE rule 

consists of three discrete sections. First, 

EPA is proposing to determine the BSER 

for existing EGUs based on HRI 

measures that can be applied at an 

affected source. EPA also proposes a 

corresponding emission guideline 

clarifying the roles of EPA and the states 

under CAA section 111(d). EPA’s 

primary role in implementing CAA 

section 111(d) is to provide emission 

guidelines that inform the development, 

submittal, and implementation of state 

plans, and to subsequently determine 

whether submitted state plans are 

approvable. Per the CAA, once EPA 

publishes a final emission guideline, 

states have the primary role of 

developing standards of performance 

consistent with application of the BSER. 

Congress also expressly required that 

EPA allow states to consider sourcespecific factors—including, among other 

factors, the remaining useful life of the 

affected source—in applying a standard 

of performance. In this way, the state 

and federal roles complement each 

other as EPA has the authority and 

responsibility to determine a nationally 

applicable BSER while the states have 

the authority and responsibility to 

establish and apply existing source 

standards of performance, in 

consideration of source-specific factors. 

Second, EPA is proposing new 

implementing regulations that apply to 

this action and any future emission 

guidelines promulgated under CAA 

section 111(d). The purpose of 

proposing new implementing 

regulations is to harmonize our 40 CFR 

part 60 subpart B regulations with the 

statute by making it clear that states 

have broad discretion in establishing 

and applying emissions standards 

consistent with the BSER. The 

discussion for the proposed revisions is 

found in Section VII below. 

Third, EPA is proposing to give the 

owners/operators of EGUs more latitude 

to make the efficiency improvements 

that are consistent with EPA’s proposed 

BSER without triggering onerous and 

costly NSR permit requirements. This 

change will allow states, in establishing 

standards of performance, to consider 

HRIs that would otherwise not be costeffective due to the burdens incurred 

from triggering NSR. The discussion of 

this issue is included in Section VII. 

As with other regulations of this 

nature, this notice concludes with a 

summary of the impacts of this proposal 

and is supported by a Regulatory Impact 

Analysis (RIA) that can be found in the 

docket for this action. As reported in the 

RIA, EPA evaluated three illustrative 

policy scenarios modeling HRI at coalfired EGUs. EPA estimates that there are 

cost savings under two of the three 

illustrative scenarios, with average 

annual compliance costs ranging from a 

cost savings of about $0.5 billion to a 

cost of about $0.3 billion. As noted 

previously, this action is preceded by a 

proposed repeal of the CPP.2 That 

proposal included a detailed legal 

analysis demonstrating that ‘‘building 

blocks’’ two and three of the CPP 

exceeded EPA’s authority. That analysis 

is incorporated into this proposal. 

Because two of the three ‘‘building 

blocks’’ used to establish the CPP 

emission guidelines were legally flawed 

(and because ‘‘building block’’ one was 

not designed in such a manner that it 

could or was intended to stand on its 

own without the other building blocks), 

EPA proposed that the CPP emission 

guidelines be withdrawn. With the ACE 

rule, EPA proposes to possibly replace 

the CPP with a rule that corrects the 

fundamental legal flaws in the CPP to 

more appropriately balance federal and 

state responsibilities under CAA section 

111(d), and revise the NSR program as 

it applies to affected EGUs to better 

accommodate energy efficiency projects. 

This proposed action has been 

informed by comments submitted in 

response to the ANPRM, published 

December 28, 2017, see 82 FR 61507. 

EPA notes that it does not intend to 

respond to the comments received on 

the ANPRM. If commenters believe that 

any of their previously submitted 

comments are still applicable, they 

should resubmit those comments to this 

rulemaking to ensure they are 

considered. 

B. Where can I get a copy of this 

document and other related 

information? 

In addition to being available in the 

docket, an electronic copy of this action 

is available on the internet. Following 

signature by the EPA Administrator, 

EPA will post a copy of this proposed 

action at https://www.epa.gov/ 

stationary-sources-air-pollution/electricutility-generating-units-emissionguidelines-greenhouse. Following 

publication in the Federal Register, EPA 

will post the Federal Register version of 

the proposal and key technical 

documents at this same website. 

II. Background 

A. Regulatory and Judicial History of 

GHG Requirements for EGUs 

When passing and amending the 

CAA, Congress sought to address and 

remedy the dangers posed by air 

pollution to human beings and the 

environment. While the text of the CAA 

does not reflect an explicit intent on the 

part of Congress to address the potential 

effects of elevated atmospheric GHG 

concentrations, the Supreme Court in 

Massachusetts v. EPA, 549 U.S. 497 

(2007), concluded that Congress had 

drafted the CAA broadly enough so that 

GHGs constituted air pollutants within 

the meaning of the CAA. EPA 

subsequently determined that emissions 

of GHGs from new motor vehicles cause 

or contribute to air pollution that may 

reasonably be anticipated to endanger 

public health or welfare. See 74 FR 

66496 (December 15, 2009). This 

determination required EPA to regulate 

GHG emissions from motor vehicles. 

In 2009, and again in 2016, the EPA 

Administrator issued findings under 

sections 202(a) and 231(a)(2)(A) of the 

Clean Air Act, respectively, that the 

current, elevated concentrations of six 

well-mixed GHGs in the atmosphere 

may reasonably be anticipated to 

endanger public health and welfare of 

current and future generations in the 


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Federal Register / Vol. 83, No. 170 / Friday, August 31, 2018 / Proposed Rules 44749 

3 ‘‘Finding that Greenhouse Gas Emissions From 

Aircraft Cause or Contribute to Air Pollution That 

May Reasonably Be Anticipated to Endanger Public 

Health and Welfare,’’ 81 FR 54422 (August 15, 

2016). 

United States.3 In 2015, after 

determining that GHGs from EGUs 

merited regulation under CAA section 

111, EPA promulgated standards of 

performance for new, modified, and 

reconstructed EGUs under section 

111(b). 80 FR 64510. Consequentially, 

this led to EPA’s obligation to develop 

a 111(d) rule for existing EGUs, as 

described in Section III. EPA believes 

that the BSER in ACE is consistent both 

with our legal authorities under 111(d) 

and with what is technically feasible 

and appropriate for coal-fired power 

plants. Therefore, EPA believes that the 

emission reductions required from state 

plans are the appropriate amount for a 

111(d) rule. 

While the market in the power sector 

is driving GHG emissions down, the 

EPA, by proposing this emission 

guideline, is reinforcing the market in 

many respects and also ensuring that 

available emission reductions that are 

not market driven are achieved. Many 

regulations are promulgated to correct 

market failures, which otherwise lead to 

a suboptimal allocation of resources 

within the free market. Air quality and 

pollution control regulations address 

‘‘negative externalities’’ whereby the 

market does not internalize the full 

opportunity cost of production borne by 

society as public goods such as air 

quality are unpriced. 

While recognizing that optimal social 

level of pollution may not be zero, GHG 

emissions impose costs on society, such 

as negative health and welfare impacts, 

that are not reflected in the market price 

of the goods produced through the 

polluting process. For this regulatory 

action the good produced is electricity. 

If a fossil fuel-fired electricity producer 

pollutes the atmosphere when it 

generates electricity, this cost will be 

borne not by the polluting firm but by 

society as a whole, thus the producer is 

imposing a negative externality, or a 

social cost of emissions. The 

equilibrium market price of electricity 

may fail to incorporate the full 

opportunity cost to society of generating 

electricity. Consequently, absent a 

regulation on emissions, the EGUs will 

not internalize the social cost of 

emissions and social costs will be 

higher as a result. This regulation will 

work towards addressing this market 

failure by causing affected EGUs to 

begin to internalize the negative 

externality associated with CO2

emissions. 

Further discussion of GHG impacts, as 

well as the benefits of this proposal, can 

be found in the RIA for this action. As 

detailed in Chapter 3 of the RIA, EPA 

evaluated three illustrative policy 

scenarios representing ACE. These 

scenarios are projected to result in a 

decrease of annual CO2 emissions of 

about 7 million to 30 million short tons 

relative to a future without a CAA 

section 111(d) regulation affecting the 

power sector. 

Along with the 111(b) standard, EPA 

issued, under CAA section 111(d), its 

‘‘Clean Power Plan,’’ consisting of GHG 

emission guidelines for existing EGUs, 

which states would use to develop 

emission standards as mentioned above. 

80 FR 64662 (October 23, 2015). In 

February 2016, the U.S. Supreme Court 

stayed implementation of the CPP 

pending judicial review. West Virginia 

v. EPA, No. 15A773 (S.Ct. Feb. 9, 2016). 

In March 2017, President Trump 

issued Executive Order 13873, which 

among other things, directed EPA to 

reconsider the CPP. After considering 

the statutory text, context, legislative 

history and purpose, and in 

consideration of EPA’s historical 

practice under CAA section 111 as 

reflected in its other existing CAA 

section 111 regulations and of certain 

policy concerns, EPA proposed to repeal 

the CPP. See 82 FR 48035. In a separate 

but related action, EPA published an 

ANPRM to solicit comment on what 

EPA should include in a potential new 

existing source regulation under CAA 

section 111(d), including soliciting 

comment on aspects of the respective 

roles of the states and EPA in that 

process, on the BSER in context of the 

statutory interpretation contained in the 

proposed repeal of the CPP, on what 

systems of emission reduction might be 

available and appropriate, and the 

potential flexibility that could be 

afforded under the NSR program to 

improve the implementation of a 

potential new existing source regulation 

for EGUs under CAA section 111(d). 82 

FR 61507 (December 28, 2017). EPA 

received more than 270,000 comments 

on the ANPRM, which have informed 

this proposed rulemaking. 

In ACE, EPA is proposing to 

determine that the BSER for GHG 

emissions from existing coal-fired EGUs 

is heat rate improvements that can be 

applied at the source, consistent with 

the legal interpretation expressed in the 

proposed repeal. The Agency is also, in 

this action, clarifying the respective 

roles of the states and EPA under CAA 

section 111(d), including by proposing 

revisions to the regulations, in 40 CFR 

part 60 subpart B, implementing that 

section. Section 111(d)(1) of the CAA 

states that EPA’s ‘‘Administrator shall 

prescribe regulations which shall 

establish a procedure . . . under which 

each State shall submit to the 

Administrator a plan which (A) 

establishes standards of performance for 

any existing source for any air pollutant 

. . . to which a standard of performance 

under this section would apply if such 

existing source were a new source, and 

(B) provides for the implementation and 

enforcement of such standards of 

performance.’’ See 42 U.S.C. 7411(d). 

CAA section 111(d)(1) also requires the 

Administrator to ‘‘permit the State in 

applying a standard of performance to 

any particular source under a plan 

submitted under this paragraph to take 

into consideration, among other factors, 

the remaining useful life of the existing 

source to which such standard applies.’’ 

Id. 

As the plain language of the statute 

provides, EPA’s authorized role under 

CAA section 111(d)(1) is to develop a 

procedure for states to establish 

standards of performance for existing 

sources. Indeed, the Supreme Court has 

acknowledged the role and authority of 

states under section 111(d): This 

provision allows ‘‘each State to take the 

first cut at determining how best to 

achieve EPA emissions standards within 

its domain.’’ Am. Elec. Power Co. v. 

Connecticut, 131 S. Ct. 2527, 2539 

(2011). The Court addressed the 

statutory framework as implemented 

through regulation, under which EPA 

promulgates emission guidelines and 

the states establish performance 

standards: ‘‘For existing sources, EPA 

issues emissions guidelines; in 

compliance with those guidelines and 

subject to federal oversight, the States 

then issue performance standards for 

stationary sources within their 

jurisdiction, [42 U.S.C.] § 7411(d)(1).’’ 

Id. at 2537–38. 

As contemplated by CAA section 

111(d)(1), states possess the authority 

and discretion to establish appropriate 

standards of performance for existing 

sources. CAA section 111(a)(1) defines 

‘‘standard of performance’’ as ‘‘a 

standard of emissions of air pollutants 

which reflects’’ what is colloquially 

referred to as the ‘‘Best System of 

Emission Reduction’’ or ‘‘BSER’’—i.e., 

‘‘the degree of emission limitation 

achievable through the application of 

the best system of emission reduction 

which (taking into account the cost of 

achieving such reduction and any 

nonair quality health and environmental 

impact and energy requirements) the 

Administrator determines has been 

adequately demonstrated.’’ 42 U.S.C. 

7411(a)(1) (emphasis added). 


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4See Section VII.A. for proposed changes to the 

definition of ‘‘emission guideline’’ as part of EPA’s 

proposed new implementing regulations. 

5See also 40 FR 53343 (‘‘If there is to be 

substantive review, there must be criteria for the 

review, and EPA believes it is desirable (if not 

legally required) that the criteria be made known in 

advance to the States, to industry, and to the 

general public. The emission guidelines, each of 

which will be subjected to public comment before 

final adoption, will serve this function.’’). 

6EPA also withdrew the proposed federal plan 

and model trading rules, proposed amendments to 

certain regulations under 40 CFR part 60, subpart 

B, implementing CAA section 111(d), and proposed 

rule regarding the Clean Energy Incentive Plan. 82 

FR 16144 (April 3, 2017). 

In order to effectuate the Agency’s 

role under CAA section 111(d)(1), EPA 

promulgated implementing regulations 

in 1975 to provide a framework for 

subsequent EPA rules and state plans 

under section 111(d). See 40 CFR part 

60, subpart B (hereafter referred to as 

the ‘‘implementing regulations’’). The 

implementing regulations reflect EPA’s 

principal task under CAA section 

111(d)(1), which is to develop a 

procedure for states to establish 

standards of performance for existing 

sources through state plans. EPA is 

proposing to promulgate an updated 

version of the implementing regulations 

as part of ACE (see Section VII). Per the 

new proposed implementing 

regulations, EPA effectuates its role by 

publishing, an ‘‘emission guideline’’ 4

that, among other things, contains EPA’s 

determination of the BSER for the 

category of existing sources being 

regulated. See 40 CFR 60.22a(b) 

[‘‘Guideline documents published under 

this section will provide information for 

the development of State plans, such as: 

. . . (4) An emission guideline that 

reflects the application of the best 

system of emission reduction 

(considering the cost of such reduction) 

that has been adequately 

demonstrated.’’] In undertaking this 

task, EPA ‘‘will specify different 

emissions guidelines . . . for different 

sizes, types and classes of . . . facilities 

when costs of control, physical 

limitations, geographic location, or 

similar factors make subcategorization 

appropriate.’’ 40 CFR 60.22(b)(5). 

In short, under EPA’s new proposed 

regulations implementing CAA section 

111(d), which tracks with the existing 

implementing regulations in this regard, 

the guideline document serves to 

‘‘provide information for the 

development of state plans.’’ 40 CFR 

60.22a(b), with the ‘‘emission 

guideline,’’ reflecting BSER as 

determined by EPA, being the principal 

piece of information states rely on to 

develop their plans that establish 

standards of performance for existing 

sources. 

Because the CAA cannot necessarily 

be applied to GHGs in the same manner 

as other pollutants, Utility Air 

Regulatory Group, 134 S. Ct. 2427, 2455 

(2014) (Alito, J., concurring in part and 

dissenting in part), it is fortuitous that 

CAA section 111(d) recognizes that 

states possess considerable flexibility in 

developing their plans in response to 

the emissions guideline(s) established 

by EPA. Specifically, the Act requires 

that EPA permit states to consider, 

‘‘among other factors, the remaining 

useful life’’ of an existing source in 

applying a standard of performance to 

such sources. CAA section 111(d)(1). 

Additionally, while CAA section 

111(d)(1) clearly authorizes states to 

develop state plans that establish 

performance standards and provides 

states with certain discretion in 

determining appropriate standards, 

CAA section 111(d)(2) provides EPA 

specifically a role with respect to such 

state plans. This provision authorizes 

EPA to prescribe a plan for a state ‘‘in 

cases where the State fails to submit a 

satisfactory plan.’’ CAA section 

111(d)(2)(A). EPA therefore is charged 

with determining whether state plans 

developed and submitted under section 

111(d)(1) are ‘‘satisfactory,’’ and the 

proposed new implementing regulations 

at 40 CFR 60.27a accordingly provides 

timing and procedural requirements for 

EPA to make such a determination. Just 

as guideline documents may provide 

information for states in developing 

plans that establish standards of 

performance, they may also provide 

information for EPA to consider when 

reviewing and taking action on a 

submitted state plan, as the new 

proposed implementing regulations at 

40 CFR 60.27a(c) references the ability 

of EPA to find a state plan as 

‘‘unsatisfactory because the 

requirements of (the implementing 

regulations) have not been met.’’ 5

B. Executive Order 13783 and EPA’s 

Review of the CPP 

On March 28, 2017, President Trump 

issued Executive Order 13783, which 

affirms the ‘‘national interest to promote 

clean and safe development of our 

Nation’s vast energy resources, while at 

the same time avoiding regulatory 

burdens that unnecessarily encumber 

energy production, constrain economic 

growth, and prevent job creation.’’ See 

Executive Order 13783, Section 1(a). 

The Executive Order directs all 

executive departments and agencies, 

including EPA, to ‘‘immediately review 

existing regulations that potentially 

burden the development or use of 

domestically produced energy resources 

and appropriately suspend, revise, or 

rescind those that unduly burden the 

development of domestic energy 

resources beyond the degree necessary 

to protect the public interest or 

otherwise comply with the law.’’ Id. 

Section 1(c). The Executive Order 

further affirms that it is ‘‘the policy of 

the United States that necessary and 

appropriate environmental regulations 

comply with the law.’’ Id. Section 1(e). 

Moreover, the Executive Order 

specifically directs EPA to review and 

initiate reconsideration proceedings to 

‘‘suspend, revise, or rescind’’ the CPP, 

‘‘as appropriate and consistent with 

law.’’ Id. Section 4(a)–(c). 

In a document signed the same day as 

Executive Order 13783, and published 

in the Federal Register at 82 FR 16329 

(April 4, 2017), EPA announced that, 

consistent with the Executive Order, it 

was initiating its review of the CPP and 

providing notice of forthcoming 

proposed rulemakings consistent with 

the Executive Order.6 In the course of 

EPA’s review of the CPP, the Agency 

also reevaluated its interpretation of 

CAA section 111, and, on that basis, the 

Agency proposed to repeal the CPP. See 

82 FR 48035. 

This action proposes a BSER for GHGs 

from existing EGUs in line with the 

interpretation presented in the proposed 

CPP repeal. See 82 FR 48038–42. 

Comments submitted on the proposed 

repeal will be considered in the 

promulgation of this rulemaking so 

there is no need to resubmit comments 

that have already been timely 

submitted. 

C. Industry Trends 

Carbon dioxide emissions in the 

power sector have steadily declined in 

recent years due to a variety of power 

industry trends, which are expected to 

continue. The reduction in power sector 

CO2 emissions is the result of industry 

trends away from coal-fired generation 

and toward low- and zero-emitting 

generation sources. These trends have 

been driven by market factors, reduced 

electricity demand, and policy and 

regulatory efforts. These trends have 

resulted in a notable change to the 

country’s overall generation mix, as 

more natural gas and renewable energy 

is used to generate electricity relative to 

coal-fired electricity. The price of 

natural gas is expected to remain low for 

the foreseeable future as improvements 

in drilling technologies and techniques 

continue to reduce the cost of 

extraction. In addition, the existing fleet 

of coal-fired EGUs is aging and there are 

very few new coal-fired generation 


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7U.S. EIA, Annual Energy Outlook 2018 with 

projections to 2050 (February 6, 2018), at 102, 

available at https://www.eia.gov/outlooks/aeo/pdf/ 

AEO2018.pdf. 

projects under development. With a 

continued (but reduced) tax credit and 

declining capital costs, solar capacity 

will continue to grow through 2050 

while tax credits that phase out for 

plants entering service through 2024 

provide incentives for new wind 

capacity in the near-term. Some power 

plant generators have announced that 

they expect to continue to change their 

generation mix away from coal-fired 

generation toward natural-gas fired 

generation, renewables and more 

deployment of energy efficiency 

measures. All of these trends, in total, 

are expected to result in declining 

power sector CO2 emissions. 

In the near-term, according to the U.S. 

Energy Information Administration’s 

(EIA) 2018 Annual Energy Outlook, ‘‘the 

cumulative effect of increased coal plant 

retirements, lower natural gas prices 

and lower electricity demand in the 

AEO2018 Reference case is a reduction 

in the projected [CO2] emissions from 

electric generators, even without the 

[CPP]. In 2020, electric power sector 

CO2 emissions are projected to be 1.72 

billion metric tons, which is 120 million 

metric tons (7 percent) lower than the 

projected level of CO2 emissions in the 

AEO2017 Reference case without the 

CPP.’’ 7 In other words, these declining 

emission trends have continued to 

develop even in the absence of 

implementation of the CPP. 

In consideration of these ongoing and 

projected power sector trends and a 

resulting decline in power sector CO2

emissions, EPA is soliciting comment 

on whether and how to consider such 

trends in developing CO2 emission 

guidelines for the power sector. A 

comparison of EIA projections to EPA 

analysis for the original proposed CPP 

demonstrates that the rapid changes in 

the power sector are leading to CO2

emission reductions at a faster rate than 

projected even a few years ago when the 

CPP was promulgated (Comment C–1). 

EPA also notes that CO2 emissions are 

projected to increase over time in some 

EIA AEO side cases, and, given the 

uncertainties associated with long-term 

emission projections, solicits comments 

on the applicability of those alternative 

results. 

Because of the rapid pace of these 

power sector changes, it is difficult for 

sector analysts to fully account for these 

changing trends in near-term and longterm sector-wide projections. This 

means that regulatory decisions made 

today could be based on information 

that may very well be outdated within 

the next several years. If that is the case, 

work put in by federal and state 

regulatory agencies—as well as by the 

affected sources themselves—to address 

section 111(d) requirements could 

quickly be overtaken by external market 

forces which could make those efforts 

redundant or, even worse, put them in 

conflict with industry trends that are 

already reducing CO2 emissions. 

III. Legal Authority 

A. Authority To Revisit Existing 

Regulations 

EPA’s ability to revisit existing 

regulations is well-grounded in the law. 

Specifically, EPA has inherent authority 

to reconsider, repeal or revise past 

decisions to the extent permitted by law 

so long as the Agency provides a 

reasoned explanation. The CAA 

complements EPA’s inherent authority 

to reconsider prior rulemakings by 

providing the Agency with broad 

authority to prescribe regulations as 

necessary. 42 U.S.C. 7601(a); see also 

Emission Guidelines and Compliance 

Times for Municipal Solid Waste 

Landfills, 81 FR 59276, 59277–78 

(August 29, 2016). The authority to 

reconsider prior decisions exists in part 

because EPA’s interpretations of statutes 

it administers ‘‘[are not] instantly carved 

in stone,’’ but must be evaluated ‘‘on a 

continuing basis.’’ Chevron U.S.A. Inc. 

v. NRDC, Inc., 467 U.S. 837, 863–64 

(1984). This is true when, as is the case 

here, review is undertaken ‘‘in response 

to . . . a change in administrations.’’ 

National Cable & Telecommunications 

Ass’n v. Brand X Internet Services, 545 

U.S. 967, 981 (2005). Indeed, ‘‘[a]gencies 

obviously have broad discretion to 

reconsider a regulation at any time.’’ 

Clean Air Council v. Pruitt, 862 F.3d 1, 

8–9 (D.C. Cir. 2017). 

B. Authority To Regulate EGUs 

In the CPP, EPA stated that EPA’s 

then-concurrent promulgation of 

standards of performance regulating CO2

emissions from new, modified, and 

reconstructed EGUs triggered the need 

to regulate existing sources under CAA 

section 111(d). 80 FR 64715. In ACE, we 

are not re-opening any issues related to 

this conclusion, but for the convenience 

of stakeholders and the public, we will 

summarize our explanation here. 

We explained in the CPP that CAA 

section 111(d)(1) requires EPA to 

promulgate regulations under which 

states must submit state plans regulating 

‘‘any existing source’’ of certain 

pollutants ‘‘to which a standard of 

performance would apply if such 

existing source were a new source.’’ Id. 

Under CAA section 111(a)(2) and 40 

CFR 60.15(a), a ‘‘new source’’ is defined 

as any stationary source, the 

construction, modification, or 

reconstruction of which is commenced 

after the publication of proposed 

regulations prescribing a standard of 

performance under CAA section 111(b) 

applicable to such source. We noted 

that, at that time, we were concurrently 

finalizing a rulemaking under CAA 

section 111(b) for CO2 emissions from 

affected EGUs, which provided the 

requisite predicate for applicability of 

CAA section 111(d). Id. 

EPA explained in the 111(b) rule (80 

FR 64529) that ‘‘CAA section 

111(b)(1)(A) requires the Administrator 

to establish a list of source categories to 

be regulated under section 111. A 

category of sources is to be included on 

the list ‘if in [the Administrator’s] 

judgment it causes, or contributes 

significantly to, air pollution which may 

reasonably be anticipated to endanger 

public health and welfare.’ ’’ This 

determination is commonly referred to 

as an ‘‘endangerment finding’’ and that 

phrase encompasses both the ‘‘causes or 

contributes significantly’’ component 

and the ‘‘endanger public health and 

welfare’’ component of the 

determination. Then, for the source 

categories listed under section 

111(b)(1)(A), the Administrator 

promulgates, under section 111(b)(1)(B), 

‘‘standards of performance for new 

sources within such category.’’ EPA 

further explained that, because EGUs 

had previously been listed, it was 

unnecessary to make an additional 

finding. The Agency also noted that, 

under section 111(b)(1)(A), findings are 

category specific and not pollutant 

specific, so a new finding is not needed 

with regard to a new pollutant. The 

Agency further asserted that, even if it 

were required to make a finding, given 

the large amount of CO2 emitted from 

this source category (the largest single 

stationary source category of emissions 

of CO2 by far) that EGUs would easily 

meet that standard. The Agency further 

noted that, given the large amount of 

emissions from the source category, it 

was not necessary in that rule ‘‘for the 

EPA to decide whether it must identify 

a specific threshold for the amount of 

emissions from a source category that 

constitutes a significant contribution.’’ 

80 FR 64531. 

That CAA section 111(b) rulemaking 

remains on the books, although EPA is 

currently considering revising it. 

Accordingly, it continues to provide the 

requisite predicate for applicability of 

CAA section 111(d). Any comments on 

the issues discussed in this subsection 

would be more appropriately addressed 


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8See 40 CFR 52.21(b)(12); see also 42 U.S.C. 

7479(3). 

9The five steps are: (1) Identify all available 

control technologies; (2) eliminate technically 

infeasible options; (3) rank remaining control 

technologies; (4) evaluate most effective controls 

and document results; and (5) select the BACT. 

10New Source Review Workshop Manual, at B.13 

(Draft) (October 1990), available at https://

www.epa.gov/sites/production/files/2015-07/ 

documents/1990wman.pdf. 

to the docket on EPA’s intended 

forthcoming proposal with regard to the 

new source rule. 

C. Legal Authority for Determination of 

the BSER 

As discussed above, EPA’s authorized 

role under CAA section 111(d) is to 

establish a procedure under which 

states submit plans establishing 

standards of performance for existing 

sources, reflecting the application of the 

best system of emission reduction that 

EPA has determined is adequately 

demonstrated for the source category. In 

the CPP, EPA determined that the BSER 

for CO2 emissions from existing fossil 

fuel-fired power plants was the 

combination of emission rate 

improvements and limitations on 

overall emissions by affected power 

plants that can be accomplished through 

a combination of three sets of measures, 

which the EPA called ‘‘building 

blocks’’: 

1. Improving heat rate at affected coalfired steam generating units; 

2. Substituting increased generation 

from lower-emitting existing natural gas 

combined cycle units for decreased 

generation from higher-emitting affected 

steam generating units; and 

3. Substituting increased generation 

from new zero-emitting renewable 

energy generating capacity for decreased 

generation from affected fossil fuel-fired 

generating units. 

While building block 1 constituted 

measures that could be applied directly 

to a source—that is, integrated into its 

design or operation—building blocks 2 

and 3 employed generation-shifting 

measures that departed from this 

traditional, source-specific approach to 

regulation. 

As explained in the proposed repeal, 

after reconsidering the statutory text, 

context and legislative history, and in 

consideration of EPA’s historical 

practice under CAA section 111 as 

reflected in its other existing section 111 

regulations, the Agency proposes to 

return to a reading of section 111(a)(1) 

(and its constituent term, ‘‘best system 

of emission reduction’’) as being limited 

to emission reduction measures that can 

be applied to or at an individual 

stationary source. That is, such 

measures must be based on a physical 

or operational change to a building, 

structure, facility or installation at that 

source rather than measures the source’s 

owner or operator can implement at 

another location. For a more detailed 

discussion of EPA’s proposed 

interpretation, see 82 FR 48039–42. 

In proposing ACE, EPA offers 

additional legal rationale to support its 

determination that heat-rate 

improvements constitute the BSER. EPA 

solicits comment on these additional 

legal interpretations (Comment C–2). 

First, as explained in the CPP 

preamble, reduced utilization ‘‘does not 

fit within our historical and current 

interpretation of the BSER.’’ See 80 FR 

64780; see also id. at 64762 (‘‘EPA has 

generally taken the approach of basing 

regulatory requirements on controls and 

measures designed to reduce air 

pollutants from the production process 

without limiting the aggregate amount 

of production.’’) Whereas some 

emission reduction measures (such as a 

scrubber) may have an incidental 

impact on a source’s production levels, 

reduced utilization is directly correlated 

with a source’s output. Moreover, 

predicating a CAA section 111 standard 

on a source’s non-performance would 

inappropriately inject the Agency into 

an owner/operator’s production 

decisions. In returning to our historical 

understanding of and practice under 

section 111, we reiterate that reduced 

utilization is not a valid system of 

emission reduction for purposes of 

establishing a standard of performance. 

EPA believes our proposed 

interpretation that the BSER be limited 

to measures that can be applied at or to 

a source does not command a different 

result. 

Second, as explained in the proposed 

repeal notice, interpretative constraints 

that may apply to interpreting CAA 

section 111(a)(1) (i.e., determining what 

types of measures that may be 

considered as the BSER) for purposes of 

setting a new source performance 

standard under section 111(b) 

reasonably may be applied to 

interpreting the BSER for purposes of 

setting existing source standards under 

section 111(d) as well (and, given that 

‘‘standard of performance’’ is given a 

unitary definition for purposes of the 

entire statutory section, applying the 

same interpretative constraints may in 

fact be required). For example, we 

proposed that ‘‘the BSER should be 

interpreted as a source-specific measure, 

in light of the fact that [Best Available 

Control Technology, or BACT] 

standards, for which the BSER is 

expressly linked by statutory text, are 

unambiguously intended to be sourcespecific.’’ 8 See 82 FR 48042. 

Under the CAA and applicable 

regulations, certain preconstruction 

permits must contain emissions 

limitations based on application of 

BACT for certain regulated pollutants. 

EPA recommends that permitting 

authorities follow a five-step ‘‘topdown’’ BACT analysis, which calls for 

all available control technologies for a 

given pollutant to be identified and 

ranked in descending order of control 

effectiveness.9 The options are then 

assessed in consideration of technical, 

energy, environmental and economic 

factors until an option is selected as 

BACT. 

In reviewing our BACT guidance, we 

have identified additional interpretive 

constraints that may be applied to CAA 

section 111. Specifically, in EPA’s PSD 

and Title V Permitting Guidance for 

Greenhouse Gases, we explained that a 

BACT analysis ‘‘need not necessarily 

include inherently lower polluting 

processes that would fundamentally 

redefine the nature of the source 

proposed by the permit applicant.’’ Id. 

at 26 (emphasis added). Furthermore, 

we explained that ‘‘BACT should 

generally not be applied to regulate the 

applicant’s purpose or objective for the 

proposed facility.’’ Id. Indeed, ‘‘EPA has 

recognized that the initial list of control 

options for a BACT analysis does not 

need to include ‘clean fuel’ options that 

would fundamentally redefine the 

source. Such options include those that 

would require a permit applicant to 

switch to a primary fuel type (i.e., coal, 

natural gas or biomass) other than the 

type of fuel that an applicant proposes 

to use for its primary combustion 

process.’’ Id. at 27. EPA has even noted 

that ‘‘applicants proposing to construct 

a coal-fired electric generator, have not 

been required by EPA as part of a BACT 

analysis to consider building a natural 

gas-fired electric turbine although the 

turbine may be inherently less polluting 

per unit product (in this case 

electricity).’’ 10 Although in the CPP we 

believed that EPA’s ‘‘redefining the 

source’’ policy was not relevant for 

purposes of section 111(d), see CPP RTC 

Chapter 1A, 170–72, we now believe 

that such a policy is relevant in light of 

the relationship between BACT and 

BSER. In the response to comments 

accompanying the CPP, EPA rejected 

the relevance to BSER under section 111 

of the Agency’s general policy against 

‘‘redefining the source’’ in the context of 

PSD/BACT. EPA now believes that it 

was incorrect in its response, and that 

it is worth examining this point in some 

detail because it encapsulates several 

key aspects of the CPP’s interpretation 


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11Section 113 of Senate Bill 4538 would become 

CAA section 111; section 114 of the Senate Bill 

would become CAA section 111(d). 

of section 111 in general and section 

111(d) in particular that EPA now 

proposes to conclude in ACE are not 

appropriate interpretations of the 

statute. 

In its response to comments, EPA 

largely based its rejection of the 

relevance of PSD to BSER on what it 

saw as the salient distinctions between 

the sources subject to, and mode of 

operation of, the two statutory 

programs. In this regard, EPA spoke of 

the ‘‘distinct context of the PSD 

program, which involves the case-bycase review of the construction of an 

individual stationary source. . . . BACT 

is not applicable to unmodified existing 

sources nor is it applied on a source 

category basis. The CAA’s PSD program 

is administered primarily by state and 

local permitting authorities as [an] 

individualized preconstruction 

requirement under CAA section 165. 

Under section 111(d), the Administrator 

identifies a list of adequately 

demonstrated control options in use by 

the industry, selects the best of those 

control options after considering cost 

and other factors, then selects an 

achievable limit for the category through 

the application of the BSER across the 

industry. . . .’’ (Emphases added.) 

Here, EPA’s response disregarded the 

fact that under CAA section 111(d), the 

statute explicitly tasks states—not the 

Administrator—with ‘‘establishing 

standards of performance’’ for existing 

sources, and that the statute expressly 

requires EPA to allow the state to take 

into account source-specific factors 

when doing so. A ‘‘standard of 

performance’’ is defined at section 

111(a)(1) as ‘‘a standard for emissions of 

air pollutants which reflects the degree 

of emission limitation achievable 

through the application of the’’ BSER. 

(Emphasis added.) Therefore, it is the 

state, not EPA, that is tasked in the first 

instance with ‘‘select[ing] an achievable 

limit’’ for existing sources—and section 

111(d)’s emphasis on source-specific 

factors at the very least renders 

questionable EPA’s unqualified 

assertion that BSER for existing sources 

‘‘is applied on a source category basis.’’ 

In the instant proposal, EPA proposes to 

give full meaning to these textual and 

structural features of the existing-source 

program under section 111(d) that 

render it in important respects distinct 

from the new-source program under 

section 111(b) and similar to the sourceby-source PSD program: Section 111(d), 

unlike section 111(b), is implemented in 

the first instance by the states, and it is 

expressly linked to source-specific 

factors. These similarities counsel 

against EPA’s prior rejection of the 

relevance of the general policy under 

PSD against ‘‘redefining the source.’’ 

Furthermore, speaking of the 

generation-shifting measures that 

constituted the second and third 

‘‘building blocks’’ of the CPP, EPA 

asserted that ‘‘those measures are part of 

the business purposes and objectives 

within the power sector. Accordingly, 

the BSER, which incorporates building 

blocks 2 and 3, cannot be said to force 

a fundamental redefinition of the 

business of generating electric power.’’ 

(Emphases added.) The emphasized 

phrases reveal the influence of EPA’s 

statutory interpretation underlying the 

CPP: That EPA can regulate under CAA 

section 111 at the level of an entire 

industrial sector, and that the business 

that it is regulating is ‘‘generating 

electric power’’ writ large—rather than 

a recognition in line with the statute’s 

text and structure, and EPA’s practice 

prior to the CPP, of regulating the 

performance of individual sources 

through measures carried out at and by 

the individual source. 

EPA rested on its discretionary 

prerogative: ‘‘EPA’s policies under CAA 

section 165 regarding the construction 

of individual sources are not controlling 

for purposes of establishing categorywide standards for existing sources 

under CAA section 111(d). Even if the 

PSD ‘redefining the source’ policies 

were applicable in this context, it would 

be within the Administrator’s discretion 

to consider requiring a fundamental 

redesign of a newly constructed or 

modified source[ ]. EPA’s case-by-case 

application of CAA section 165 in the 

PSD program does not limit the 

Administrator’s discretion in 

establishing an emission guideline for 

an entire category of existing sources 

under CAA section 111(d).’’ (Emphases 

added.) EPA has explained, both in the 

proposed repeal and the instant 

proposal, why it is proposing to 

conclude that the statute does not, in 

fact, delegate discretion to the 

Administrator to ‘‘establish . . . for an 

entire category of existing sources’’ 

standards that can only be 

accomplished by ‘‘a fundamental 

redesign’’ of that category, of the 

generation mix, and of the division of 

jurisdiction over electricity generation 

within the federal government and 

between the federal government and the 

states. But to the extent that the Agency, 

due to the fact that Congress did not 

expressly forbid such an approach, does 

possess that discretion, today it 

proposes not to exercise it. 

Third, notwithstanding the 

relationship between BACT and BSER, 

we believe that measures ‘‘redefining 

the source’’ should be excluded from 

consideration for purposes of CAA 

section 111(d). See, e.g., Sierra Club v. 

EPA, 499 F.3d 653, 655 (7th Cir. 2007) 

(‘‘Refining the statutory definition . . . 

to exclude redesign is the kind of 

judgment by an administrative agency to 

which a reviewing court should defer.’’). 

Indeed, the policy against redefining a 

source is even more sensible when 

applied to existing sources. Under 

section 111(d), regulated sources are 

well past the proposal stage and 

redefining such sources would likely 

require, at a minimum, significant 

modification and could even require 

decommissioning, redesign and new 

construction. Accordingly, we propose 

to recognize that the BSER analysis need 

not include options that would 

‘‘fundamentally redefine the source,’’ 

irrespective of the application of that 

policy under PSD. For purposes of ACE, 

therefore, we did not consider natural 

gas repowering (i.e., converting from a 

coal-fired boiler to a gas-fired turbine) or 

refueling (i.e., converting from a coalfired boiler to a natural gas-fired boiler) 

as a system of emission reduction for 

coal-fired steam generating units. 

Fourth, the legislative history 

underlying CAA section 111 confirms 

that Congress intended this provision to 

be source oriented. The Senate 

Committee Report on Senate Bill 4358 

explained that ‘‘[t]he provisions for new 

source performance standards [i.e., S. 

4538, section 113] 11 are designed to 

insure [sic] that new stationary sources 

are designed, built, equipped, operated, 

and maintained so as to reduce 

emissions to a minimum.’’ S. Committee 

Rep. to accompany S. 4358 (Sept. 17, 

1970), 1970 CAA Legis. Hist. at 415–16 

(emphasis added). Similarly, 

‘‘[e]mission standards developed under 

[S. 4538, section 114] would be applied 

to existing stationary sources. However, 

the Committee recognizes that certain 

old facilities may use equipment and 

processes which are not suited to the 

application of control technology.’’ Id. 

at 1970 CAA Legis. Hist. at 419 

(emphasis added) (noting further that in 

such cases, the application of standards 

could be waived). 

The proposed interpretive scope of 

the BSER is reasonable because it 

focuses the BSER on the performance of 

the emitting unit itself, rather than the 

performance of the emitting unit and the 

transmission system to which it belongs. 

EPA’s area of expertise is control of 

emissions at the source. EPA is not the 

expert agency with regard to electricity 

management. FERC is the expert at the 


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12U.S. DOE, Staff Report to the Secretary on 

Electricity Markets and Reliability (August 2017) at 

14, available at https://www.energy.gov/sites/prod/ 

files/2017/08/f36/Staff%20Report%20on%20

Electricity%20Markets%20and%20Reliability_

0.pdf. 

13Under section 111(a) of the CAA, determination 

of affected sources is based on the date that EPA 

proposes action on such sources. January 8, 2014 

is the date the proposed GHG standards of 

performance for new fossil fuel-fired EGUs were 

published in the Federal Register (79 FR 1430). 14To be clear, this definition of an affected EGU 

does not, at this time, include stationary 

combustion turbines for reasons discussed later in 

this document. 

federal level and public utility 

commissions are the experts at the state 

and local level. Numerous factors might 

be considered in determining which 

power plants dispatch on a given system 

or operate at any given time (e.g., cost 

of service, voltage support, electricity 

demand, availability of renewable 

resources, etc.). Moreover, numerous 

factors are relevant in determining how 

much new/replacement generation 

capacity is needed and what types of 

generating resources best satisfy that 

need. EPA has no express legal 

authority and no particular expertise in 

any of these areas. This is particularly 

relevant because, as noted below, there 

are already significant changes taking 

place within the power sector that are 

resulting in shifts away from coal-fired 

generation to new technologies such as 

renewables. This shift is creating 

tremendous strain on the power 

infrastructure even without the added 

pressures of an EPA mandate to further 

shift away from additional coal-fired 

generation. Many experts have 

expressed concern that these pressures 

could create reliability problems. As 

DOE noted in a 2017 report on 

electricity markets and reliability, 

‘‘Ultimately, the continued closure of 

traditional baseload power plants calls 

for a comprehensive strategy for longterm reliability and resilience. States 

and regions are accepting increased 

risks that could affect the future 

reliability and resilience of electricity 

delivery for consumers in their regions. 

Hydropower, nuclear, coal, and natural 

gas power plants provide essential 

reliability services and fuel assurance 

critical to system resilience. A continual 

comprehensive regional and national 

review is needed to determine how a 

portfolio of domestic energy resources 

can be developed to ensure grid 

reliability and resilience.’’ 12 Because 

EPA believes it is not appropriate to 

further challenge the nation’s electricity 

system while these important technical 

and policy issues are being addressed. 

EPA believes that it is reasonable to 

focus on a ‘‘BSER’’ limited to 

consideration of emission control 

measures that can be applied at or to 

coal-fired units, ensuring that regardless 

of how much coal-fired generation 

remains, that generation is operated to 

minimize CO2 emissions. 

Also, the proposed interpretive scope 

of the BSER is reasonable considering 

the several important economic, policy 

and technology shifts occurring in the 

power sector. The first change is being 

driven by low natural gas prices that 

make lower carbon-emitting NGCC units 

more competitive as compared to higher 

carbon-emitting coal plants. Another 

important change is driven by both 

technology changes and by state and 

national energy policy decisions that 

have made renewable energy (e.g., solar 

and wind energy) more competitive 

compared to coal and natural gas. The 

third notable change is driven by aging 

coal plants, which considering the 

economic competitive pressures driven 

by natural gas and renewable 

generation, are leading companies to 

conclude that a significant number of 

coal plants are reaching the end of their 

useful economic life or are no longer 

economic to operate. 

These trends have driven down GHG 

emissions from power plants, which 

were also key components to the BSER 

as defined in the CPP. In fact, the 

analysis that EPA has done for ACE (see 

RIA), as well as analysis by many others 

(including EIA), show that these trends 

have already well outpaced the 

projections that went into the CPP for 

many states. For this reason, 

establishing a BSER on assumptions for 

generation by various sources that 

accounts for the continuation of these 

trends into the future would create 

significant work for both states and 

sources that may or may not result in 

emission reductions from ACE if the 

actual trends once again prove to be 

stronger than projected. 

While some might suggest that this 

argues that the BSER in ACE should still 

follow the same approach as the CPP, 

adjusting this proposal to be even more 

stringent ignores the fact that the 

uncertainties that have resulted in faster 

than projected emission reductions are 

also uncertain in the opposite direction. 

From 2005 to 2008, gas prices 

experienced several unexpected peaks 

that were not anticipated. If this were to 

happen in the future, it would make any 

rule based on CPP-type assumptions 

significantly more expensive. Similarly, 

while the recent past has shown 

continued advances in renewable cost 

and performance, it is not certain that 

those trends will be sustained. It should 

be noted that federal tax subsidies that 

have been key to this trend are set to 

expire over the next several years which 

may play a role in the future. 

Because of these significant 

uncertainties that can have large 

impacts on electric reliability and the 

cost of electricity to consumers, EPA 

believes that this further supports the 

unreasonableness of basing the BSER on 

generation-shifting measures. Regardless 

of the path that the power sector takes, 

coal-fired power plants are likely to be 

an important part of the generation mix 

for the foreseeable future, therefore EPA 

believes it is reasonable to ensure that 

the remaining coal-fired generation 

(which is also the most CO2 intensive 

portion of the power sector) focuses on 

reducing that CO2 emission intensity to 

the extent technically feasible 

considering cost. 

EPA believes that a BSER focused on 

making these plants as efficient as 

possible is the best way to ensure GHG 

emission reductions regardless of other 

factors such as technology changes for 

other types of generation, changes in 

fuel price, changes in electricity 

demand or changes in energy policy that 

neither environmental regulators nor 

power companies have the power to 

control. 

IV. Affected Sources 

EPA is proposing that an affected EGU 

subject to regulation upon finalization 

of ACE is any fossil fuel-fired electric 

utility steam generating unit (i.e., utility 

boilers) that is not an integrated 

gasification combined cycle (IGCC) unit 

(i.e., utility boilers, but not IGCC units) 

that was in operation or had 

commenced construction as of August 

31, 2018,13 and that meets the following 

criteria.14 To be an affected EGU, a fossil 

fuel-fired electric utility steam 

generating unit must serve a generator 

capable of selling greater than 25 MW to 

a utility power distribution system and 

have a base load rating greater than 260 

GJ/h (250 MMBtu/h) heat input of fossil 

fuel (either alone or in combination 

with any other fuel). 

EPA is proposing different 

applicability criteria than in the CPP to 

reflect EPA’s determination of the BSER 

for only fossil fuel-fired electric utility 

steam generating units. In ACE, EPA 

does not identify a BSER for stationary 

combustion turbines and IGCC units 

and, thus, such units are not affected 

EGUs for purposes of this action (see 

discussion below in Section V.B). It 

should be noted, in the CPP’s 

identification of the BSER, no HRIs were 

identified as the BSER for stationary 

combustion turbines and IGCC units. 

Nevertheless, EPA solicits comment on 

systems of emission reduction that 

might be the BSER for these types of 


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15Case law under CAA section 111(b) explains 

that ‘‘[a]n adequately demonstrated system is one 

which has been shown to be reasonably reliable, 

reasonably efficient, and which can reasonably be 

expected to serve the interests of pollution control 

without becoming exorbitantly costly in an 

economic or environmental way.’’ Essex Chemical 

Corp. v. Ruckelshaus, 486 F.2d 427, 433–34 (D.C. 

Cir. 1973). While some of these cases suggest that 

‘‘[t]he Administrator may make a projection based 

on existing technology,’’ Portland Cement Ass’n v. 

Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973), the 

D.C. Circuit has also noted that ‘‘there is inherent 

tension’’ between considering a particular control 

technique as both ‘‘an emerging technology and an 

adequately demonstrated technology,’’ Sierra Club 

v. Costle, 657 F.2d 298, 341 n.157 (D.C. Cir. 1981). 

See also NRDC v. Thomas, 805 F.2d 410, n. 30 (D.C. 

Cir. 1986) (suggesting that ‘‘a standard cannot both 

require adequately demonstrated technology and 

also be technology-forcing.’’). Nevertheless, EPA 

appears to ‘‘have authority to hold the industry to 

a standard of improved design and operational 

advances, so long as there is substantial evidence 

that such improvements are feasible.’’ Sierra Club, 

657 F.2d at 364. 

16The D.C. Circuit recognizes that EPA’s 

evaluation of the ‘‘best’’ system must also include 

‘‘the amount of air pollution as a relevant factor to 

be weighed . . . .’’ Id. at 326. 

EGUs (Comment C–3). EPA notes that, 

under the CPP, certain EGUs were not 

considered to be affected EGUs, and 

therefore were exempt from inclusion in 

a state plan. Similarly, EPA is proposing 

for ACE, the following EGUs would be 

excluded from a state’s plan: (1) Those 

units subject to 40 CFR 60 subpart TTTT 

as a result of commencing modification 

or reconstruction; (2) steam generating 

units subject to a federally enforceable 

permit limiting net-electric sales to onethird or less of their potential electric 

output or 219,000 MWh or less on an 

annual basis; (3) non-fossil units (i.e., 

units capable of combusting at least 50 

percent non-fossil fuel) that have 

historically limited the use of fossil 

fuels to 10 percent or less of the annual 

capacity factor or are subject to a 

federally enforceable permit limiting 

fossil fuel use to 10 percent or less of 

the annual capacity factor; (4) units that 

serve a generator along with other steam 

generating unit(s) where the effective 

generation capacity (determined based 

on a prorated output of the base load 

rating of each steam generating unit) is 

25 MW or less; (5) municipal waste 

combustor unit subject to 40 CFR part 

60, subpart Eb; or (6) commercial or 

industrial solid waste incineration units 

that are subject to 40 CFR part 60, 

subpart CCCC. EPA solicits comment on 

whether there should be a different 

definition of affected EGUs for ACE 

(Comment C–4). 

V. Determination of the BSER 

CAA section 111(d)(1) directs EPA to 

promulgate regulations establishing a 

CAA section 110-like procedure under 

which states submit state plans that 

establish ‘‘standards of performance’’ for 

emissions of certain air pollutants from 

sources which, if they were new 

sources, would be subject to new source 

standards under section 111(b), and that 

provide for the implementation and 

enforcement of those standards of 

performance. The term ‘‘standard of 

performance’’ is defined in section 

111(a)(1) as ‘‘a standard for emissions of 

air pollutants which reflects the degree 

of emission limitation achievable 

through the application of the best 

system of emission reduction [BSER] 

which (taking into account the cost of 

achieving such reduction and any 

nonair quality health and environmental 

impact and energy requirements) the 

Administrator determines has been 

adequately demonstrated.’’ 

Thus, EPA is authorized to determine 

the BSER for affected sources. See also 

40 CFR 60.22. In making this 

determination, EPA identifies all 

‘‘adequately demonstrated’’ 15

‘‘system[s] of emission reduction’’ for a 

particular source category and then 

evaluates those systems to determine 

which is the ‘‘best’’ 16 while ‘‘taking into 

account’’ the factors of ‘‘cost . . . nonair 

quality health and environmental 

impact and energy requirements.’’ 

Because CAA section 111 does not set 

forth the weight that should be assigned 

to each of these factors, courts have 

granted the Agency a great degree of 

discretion in balancing them. Lignite 

Energy Council v. EPA, 198 F.3d 930, 

933 (D.C. Cir. 1999) (internal citations 

omitted). 

CAA section 111(d)(1) assigns 

responsibility to the states for 

establishing standards of performance 

for affected existing sources—in contrast 

to section 111(b), which directs EPA to 

set standards of performance for affected 

new sources. 

A. Identification of the BSER 

In ACE, EPA identified several 

systems of emission reduction for 

existing fossil-fuel fired steam 

generating EGUs (i.e., heat rate 

improvements; carbon capture and 

storage; and fuel co-firing, including 

with natural gas and biomass) and 

evaluated each of these systems to 

determine which is the ‘‘best’’ while 

taking into account cost, nonair quality 

health and environmental impact and 

energy requirements. 

EPA proposes to identify ‘‘heat rate 

improvements’’ (which may also be 

referred to as ‘‘efficiency 

improvements’’) as the BSER for 

existing fossil-fuel fired steam 

generating EGUs. The basis for this 

determination is discussed below. A 

discussion of other potential CO2

reduction measures that EPA has 

determined are not BSER (but which 

states may allow sources to use for 

compliance purposes) is also provided 

below. 

The U.S. fleet of existing coal-fired 

EGUs is a diverse group of units with 

unique individual characteristics, 

spread across the country. Coal-fired 

power plants are customized facilities 

that were designed and built to meet 

local and regional electricity needs over 

the past 100 years, with no two plants 

being identical. Geography and 

elevation, unit size, coal type, pollution 

controls, cooling system, firing method 

and utilization rate are just a few of the 

parameters that can impact the overall 

efficiency and performance of 

individual units. As a result, heat rates 

of existing coal-fired EGUs in the U.S. 

vary substantially. The variation in heat 

rates among EGUs with similar design 

characteristics, as well as year-to-year 

variation in heat rate at individual 

EGUs, indicate that there is potential for 

HRIs that can improve CO2 emission 

performance for the existing coal-fired 

EGU fleet, but that this potential may 

vary considerably at the unit level. 

EPA does not currently have 

sufficient information on adequately 

demonstrated systems of emission 

reduction—including HRI 

opportunities—for existing natural gasfired stationary combustion turbines. As 

such, the Agency is currently unable to 

determine the BSER for such units. In 

this action, EPA solicits information on 

adequately demonstrated systems of 

GHG emission reduction for such 

units—especially on the efficiency, 

applicability, and cost of such systems 

(Comment C–5). This is discussed in 

greater detail below. 

B. HRIs for Steam-Generating EGUs 

As mentioned above, EPA proposes in 

ACE to identify ‘‘heat rate 

improvements’’ as the BSER for existing 

steam generating fossil fuel-fired EGUs. 

Heat rate is a measure of efficiency that 

is commonly used in the power sector. 

The heat rate is the amount of energy 

input, measured in British thermal units 

(Btu), required to generate one kilowatthour (kWh) of electricity. The lower an 

EGU’s heat rate, the more efficiently it 

operates. As a result, an EGU with a 

lower heat rate will consume less fuel 

per kWh generated and emit lower 

amounts of CO2 and other air pollutants 

per kWh generated as compared to a less 

efficient unit. An EGU’s heat rate can be 

affected by a variety of design 

characteristics, site-specific factors, and 

operating conditions, including: 

• Thermodynamic cycle of the boiler; 


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17As discussed below, EPA modeled a range of 

potential HRIs for ACE and the Agency’s analysis 

indicates that system-wide emission decreases from 

heat rate improvements will likely outweigh any 

potential system-wide emission increases. 

Accordingly, EPA proposes to conclude that the 

‘‘rebound effect’’ does not preclude a determination 

that HRIs constitute the BSER. 

18The Agency solicits comments, nonetheless, on 

whether and how to retain building block 1 in lieu 

of the proposed approach. 

19The states, in applying the unit-specific 

standard, may also take into consideration, among 

other factors, the remaining useful life of the 

existing source to which the standard applies. See 

CAA section 111(d)(1). 

• Boiler and steam turbine size and 

design; 

• Cooling system type; 

• Auxiliary equipment, including 

pollution controls; 

• Operations and maintenance 

practices; 

• Fuel quality; and 

• Ambient conditions. 

In the CPP, EPA quantified emission 

reductions achievable through heat rate 

improvements on a regional basis (i.e., 

building block 1). The Agency 

concluded that EGUs can achieve on 

average a 4.3 percent improvement in 

the Eastern Interconnection, a 2.1 

percent improvement in the Western 

Interconnection and a 2.3 percent 

improvement in the Texas 

Interconnection. See 80 FR 64789. The 

Agency then applied all three of the 

building blocks to 2012 baseline data 

and quantified, in the form of CO2

emission rates, the reductions 

achievable in each interconnection in 

2030 and selected the least stringent as 

a national performance rate. Id. at 

64811–819. EPA noted that building 

block 1 measures could not by 

themselves constitute the BSER because 

of a potential ‘‘rebound effect.’’ 17 Id. at 

64787. 

EPA believes that building block 1, as 

constructed in CPP, does not represent 

an appropriate BSER, and ACE better 

reflects important changes in the 

formulation and application of the BSER 

in accordance with the CAA. For 

example, the percent improvement 

applied as the BSER under CPP was 

determined at the interconnect-level, 

and did not take into account remaining 

useful life or other source-specific 

factors, which are addressed in this 

proposed rule.18 The current fleet of 

existing fossil fuel-fired EGUs is quite 

diverse in terms of size, age, fuel type, 

operation (e.g., baseload, cycling), boiler 

type, etc. Many coal-fired EGUs now 

operate under load-following and 

cycling conditions as opposed to the 

steady baseload operating conditions 

that were more common a decade ago. 

There are available technologies and 

equipment upgrades, as well as best 

operating and maintenance practices, 

that EGU owners or operators may 

utilize to improve an EGU’s heat rate. In 

the ANPRM, EPA solicited information 

on a number of technology and 

equipment upgrades and good practices 

(specifically including, but not limited 

to, those that were listed in Tables 1 and 

2 of the ANPRM, see 82 FR 61514) that 

have the potential to reduce an EGU’s 

heat rate. 

Specifically, the Agency solicited 

information on: (1) Potential HRIs from 

technologies and best operating and 

maintenance practices; (2) costs of 

deploying the technologies and the best 

operating and maintenance practices, 

including applicable planning, capital 

and operating and maintenance costs; 

(3) owner and operator experiences 

deploying the technologies and 

employing best operating and 

maintenance practices; (4) barriers to or 

from deploying the technologies and 

operating and maintenance practices; 

and (5) any other technologies or 

operating and maintenance practices 

that may exist for improving heat rate, 

but were not listed in the ANPRM. 

EPA received useful information in 

the comments submitted in response to 

the ANPRM. Many commenters 

contended that any evaluation of the 

HRI potential of the coal-fired EGU fleet 

must be done on a unit-by-unit basis 

since the opportunities for HRI are 

source-specific and dependent upon the 

individual unit’s design, configuration, 

and operating and maintenance history. 

Many commenters emphasized the 

significant influence that the operating 

mode (i.e., whether the unit operates at 

consistent baseload conditions or in 

cycling or load-following mode or as a 

low capacity factor unit that is subject 

to frequent startups and shutdowns) has 

on an individual EGU’s heat rate and 

HRI potential. Many commenters also 

claimed that owners and operators of 

fossil fuel-fired EGUs already routinely 

conduct HRI efforts and, as a result, 

there are relatively few economic 

improvement opportunities available. 

1. Potential HRI Measures— 

Technologies and Equipment Upgrades 

As mentioned above, numerous 

technologies and equipment upgrades, 

as well as best operating and 

maintenance practices (which are 

discussed in the next section), have 

been identified as potential measures to 

improve an EGU’s heat rate. In the 

ANPRM, EPA solicited information on a 

large number of technology and 

equipment upgrades and best operating 

and maintenance practices that have the 

potential to reduce an EGU’s heat rate. 

See Tables 1 and 2 of the ANPRM, 82 

FR 61514. 

In this action, EPA is proposing to 

determine that heat rate improvement is 

the BSER for affected existing coal-fired 

EGUs and is proposing a list of 

‘‘candidate technologies’’ of HRI 

measures for states to use in establishing 

standards of performance under CAA 

section 111(d)(1). States can use the 

information that EPA provides on the 

‘‘degree of emission limitation 

achievable through application of the 

[BSER]’’ to establish standards of 

performance for affected EGUs covered 

by a state’s plan.19 While a large number 

of HRI measures have been identified in 

a variety of studies conducted by 

government agencies and outside groups 

(see Table 3 in ANPRM, 82 FR 61515), 

some of those identified technologies 

have limited applicability and many 

provide only negligible HRI. EPA 

believes that it would be overly 

burdensome to require States to evaluate 

the degree of emission limitation 

achievable from the application of every 

single identified HRI measure— 

including those with negligible 

benefits—at each source (or subcategory 

of sources) within their borders. 

Therefore, EPA has identified a list of 

the ‘‘most impactful’’ HRI measures that 

we are proposing to serve as 

technologies, equipment upgrades and 

best operating and maintenance 

practices that form the list of ‘‘candidate 

technologies’’ constituting the BSER. 

The candidate technologies of the BSER 

is listed in Table 1 below. Best operating 

and maintenance practices are 

discussed in the next section. States are 

expected to evaluate each of the BSER 

HRI measures in the candidate 

technologies in establishing a standard 

of performance for any particular 

source. The States, in applying a 

standard of performance, may take into 

consideration, among other factors, the 

remaining useful life of the existing 

source to which the standard would 

apply. EPA solicits comments on 

whether other unlisted HRI measures 

should also be included as part of the 

BSER and added to the candidate 

technologies (Comment C–6). EPA also 

solicits comment on each of the 

candidate technologies described 

further below, including whether any 

additional technologies should be added 

to the list, and whether there is 

additional information that EPA should 

be aware of and consider in determining 

the BSER and establishing the candidate 

technologies for HRI measures 

(Comment C–7). 

The technologies and operating and 

maintenance practices listed and 


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described below may not be available or 

appropriate for all types of EGUs; and 

some owners or operators will have 

already deployed some of the 

technologies and employed some of the 

best operating and maintenance 

practices. 

TABLE 1—SUMMARY OF MOST IMPACTFUL HRI MEASURES AND RANGE OF THEIR HRI POTENTIAL (%) BY EGU SIZE

HRI measure 

<200 MW 200–500 MW >500 MW 

Min Max Min Max Min Max 

Neural Network/Intelligent Sootblowers ... 0.5 1.4 0.3 1.0 0.3 0.9 

Boiler Feed Pumps .................................. 0.2 0.5 0.2 0.5 0.2 0.5 

Air Heater & Duct Leakage Control ......... 0.1 0.4 0.1 0.4 0.1 0.4 

Variable Frequency Drives ...................... 0.2 0.9 0.2 1.0 0.2 1.0 

Blade Path Upgrade (Steam Turbine) ..... 0.9 2.7 1.0 2.9 1.0 2.9 

Redesign/Replace Economizer ................ 0.5 0.9 0.5 1.0 0.5 1.0 

Improved O&M Practices ......................... Can range from 0 to >2.0% depending on the unit’s historical O&M practices. 

a. Neural Network/Intelligent 

Sootblower 

Neural networks. Computer models, 

known as neural networks, can be used 

to simulate the performance of the 

power plant at various operating loads. 

Typically, the neural network system 

ties into the plant’s distributed control 

system for data input (process 

monitoring) and process control. The 

system uses plant specific modeling and 

control modules to optimize the unit’s 

operation and minimize the emissions. 

This model predictive control can be 

particularly effective at improving the 

plants performance and minimizing 

emissions during periods of rapid load 

changes. The neural network can be 

used to optimize combustion 

conditions, steam temperatures, and air 

pollution control equipment. 

Intelligent Sootblowers. During 

operations at a coal-fired power plant, 

particulate matter (ash or soot) builds 

up on heat transfer surfaces. This buildup degrades the performance of the heat 

transfer equipment and negatively 

affects the efficiency of the plant. Power 

plant operators use steam injection 

‘‘sootblowers’’ to clean the heat transfer 

surfaces by removing the ash build-up. 

This is often done on a routine basis or 

as needed based on monitored operating 

characteristics. Intelligent sootblowers 

(ISB) are automated systems that use 

process measurements to monitor the 

heat transfer performance and 

strategically allocate steam to specific 

areas to remove ash buildup. 

The cost to implement an ISB system 

is relatively inexpensive if the necessary 

hardware is already installed. The ISB 

software/control system is often 

incorporated into the neural network 

software package mentioned above. As 

such, the HRIs obtained via installation 

of neural network and ISB systems are 

not necessarily cumulative. 

The efficiency improvements from 

installation of intelligent sootblowers 

are often greatest for EGUs firing 

subbituminous coal and lignite due to 

more significant and rapid fouling at 

those units as compared to EGUs firing 

bituminous coal. 

b. Boiler Feed Pumps 

A boiler feed pump (or boiler 

feedwater pump) is a device used to 

pump feedwater into a boiler. The water 

may be either freshly supplied or 

returning condensate produced from 

condensing steam produced by the 

boiler. The boiler feed pumps consume 

a large fraction of the auxiliary power 

used internally within a power plant. 

Boiler feed pumps can require power in 

excess of 10 MW on a 500–MW power 

plant. Therefore, the maintenance on 

these pumps should be rigorous to 

ensure both reliability and highefficiency operation Boiler feed pumps 

wear over time and subsequently 

operate below the original design 

efficiency. The most pragmatic remedy 

is to rebuild a boiler feed pump in an 

overhaul or upgrade. 

c. Air Heater and Duct Leakage Control 

The air pre-heater is a device that 

recovers heat from the flue gas for use 

in pre-heating the incoming combustion 

air (and potentially for other uses such 

as coal drying). Properly operating air 

pre-heaters play a significant role in the 

overall efficiency of a coal-fired EGU. A 

major difficulty associated with the use 

of regenerative air pre-heaters is air 

leakage from the combustion air side to 

the flue gas side. Air leakage affects 

boiler efficiency due to lost heat 

recovery and affects the axillary load 

since any leakage requires additional 

fan capacity. The amount of air leaking 

past the seals tends to increase as the 

unit ages. Improvements to seals on 

regenerative air pre-heaters have 

enabled the reduction of air leakage. 

d. Variable Frequency Drives (VFDs) 

VFD on ID Fans. The increased 

pressure required to maintain proper 

flue gas flow through add-on air 

pollutant control equipment may 

require additional fan power, which can 

be achieved by an induced draft (ID) fan 

upgrade/replacement or an added 

booster fan. Generally, older power 

plant facilities were designed and built 

with centrifugal fans. 

The most precise and energy-efficient 

method of flue gas flow control is use 

of VFD. The VFD controls fan speed 

electrically by using a static controllable 

rectifier (thyristor) to control frequency 

and voltage and, thereby, the fan speed. 

The VFD enables very precise and 

accurate speed control with an almost 

instantaneous response to control 

signals. The VFD controller enables 

highly efficient fan performance at 

almost all percentages of flow 

turndown. 

Due to current electricity market 

conditions, many units no longer 

operate at base-load capacity and, 

therefore, VFDs, also known as variablespeed drives on fans can greatly 

enhance plant performance at off-peak 

loads. Additionally, because utilities are 

phasing in their environmental 

equipment upgrades, new fans are 

oversized and operated at lower 

capacities until all additional 

equipment has been added. Under these 

scenarios, VFDs can significantly 

improve the unit heat rate. VFDs as 

motor controllers offer many substantial 

improvements to electric motor power 

requirements. The drives provide 

benefits such as soft starts, which 

reduce initial electrical load, excessive 

torque, and subsequent equipment wear 

during startups; provide precise speed 

control; and enable high-efficiency 

operation of motors at less than the 

maximum efficiency point. During load 

turndown, plant auxiliary power could 


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20 Lignite Energy, 198 F.3d at 933. 

21Portland Cement, 513 F.2d at 508. 

22Sierra Club, 657 F.2d at 343. 

23 Id. 

be reduced by 30–60 percent if all large 

motors in a plant were efficiently 

controlled by VFD. With unit loads 

varying throughout the year, the benefits 

of using VFDs on large-size equipment, 

such as FD or ID fans, boiler feedwater 

and condenser circulation water pumps, 

can have significant impacts. Because 

plants today usually use either new 

booster ID fans or new ID fans, the 

option of investing in VFDs generally 

appeals to plant operators since they are 

incurring long outages to install the 

either new or additional air emission 

controls equipment. There are 

circumstances in which the HRI has 

been estimated to be much higher than 

that shown in Table 1, depending on the 

operation of the unit. Cycling units 

realize the greatest gains representative 

of the upper range of HRI, whereas units 

which were designed with excess fan 

capacity will exhibit the lower range. 

VFD on Boiler Feed Pumps. VFDs can 

also be used on boiler feed water pumps 

as mentioned previously. Generally, if a 

unit with an older steam turbine is rated 

below 350 MW the use of motor-driven 

boiler feedwater pumps as the main 

drivers may be considered practical 

from an efficiency standpoint. If a unit 

cycles frequently then operation of the 

pumps with VFDs will offer the best 

results on heat rate reductions, followed 

by fluid couplings. The use of VFDs for 

boiler feed pumps is becoming more 

common in the industry for larger units. 

And with the advancements in low 

pressure steam turbines, a motor-driven 

feed pump can improve the thermal 

performance of a system up to the 600– 

MW range, as compared to the 

performance associated with the use of 

turbine drive pumps. Smaller and older 

units will generally not upgrade to a 

VFD boiler feed pump drive due to high 

capital costs. 

e. Blade Path Upgrade (Steam Turbine) 

Upgrades or overhauls of steam 

turbines offer the greatest opportunity 

for HRI on many units. Significant 

increases in performance can be gained 

from turbine upgrades when plants 

experience problems such as steam 

leakages or blade erosion. The typical 

turbine upgrade depends on the history 

of the turbine itself and its overall 

performance. The upgrade can entail 

myriad improvements, all of which 

affect the performance and associated 

costs. The availability of advanced 

design tools, such as computational 

fluid dynamics (CFD), coupled with 

improved materials of construction and 

machining and fabrication capabilities 

have significantly enhanced the 

efficiency of modern turbines. These 

improvements in new turbines can also 

be utilized to improve the efficiency of 

older steam turbines whose efficiency 

has degraded over time. Upgrades or 

overhauls of steam turbines may offer 

the greatest opportunity for HRI on 

many units. Significant increases in 

performance can be gained from turbine 

upgrades when plants experience 

problems such as steam leakages or 

blade erosion. The typical turbine 

upgrade depends on the history of the 

turbine itself and its overall 

performance. The upgrade can entail 

myriad improvements, all of which 

affect the performance and associated 

costs. 

f. Redesign/Replace Economizer 

In steam power plants, economizers 

are heat exchange devices used to 

capture waste heat from boiler flue gas 

which is then used to heat the boiler 

feedwater. This use of waste heat 

reduces the need to use extracted energy 

from the system and, therefore, 

improves the overall efficiency or heat 

rate of the unit. As with most other heat 

transfer devices, the performance of the 

economizer will degrade with time and 

use, and power plant representatives 

contend that economizer replacements 

are often delayed or avoided due to 

concerns about triggering NSR 

requirements. In some cases, 

economizer replacement projects have 

been undertaken concurrently with 

retrofit installation of selective catalytic 

reduction (SCR) systems because the 

entrance temperature for the SCR unit 

must be controlled to a specific range. 

2. Potential HRI Measures—Best 

Operating and Maintenance Practices 

Many unit operators can achieve 

additional HRI by adopting best 

operating and maintenance practices. 

The amount of achievable HRI will vary 

significantly from unit to unit. In setting 

a standard of performance for a specific 

unit or subcategory of units, states 

should consider the opportunities for 

HRI from the following actions. 

a. Adopt HRI Training for O&M Staff 

EGU operators can obtain HRI by 

adopting ‘‘awareness training’’ to ensure 

that all O&M staff are aware of best 

practices and how those practices affect 

the unit’s heat rate. 

b. Perform On-Site Appraisals To 

Identify Areas for Improved Heat Rate 

Performance 

Some large utilities have internal 

groups that can perform on-site 

evaluations of heat rate performance 

improvement opportunities. Outside 

(i.e., third party) groups can also 

provide site-specific/unit-specific 

evaluations to identify opportunities for 

HRI. 

c. Improved Steam Surface Condenser— 

Cleaning 

Effective operation of the steam 

surface condenser in a power plant can 

significantly improve a unit’s heat rate. 

In fact, in many cases it can pose the 

most significant hindrance to a plant 

trying to maintain its original design 

heat rate. Since the primary function of 

the condenser is to condense steam 

flowing from the last stage of the steam 

turbine to liquid form, it is most 

desirable from a thermodynamic 

standpoint that this occurs at the lowest 

temperature reasonably feasible. By 

lowering the condensing temperature, 

the backpressure on the turbine is 

lowered, which improves turbine 

performance. 

Condenser Cleaning. A condenser 

degrades primarily due to fouling of the 

tubes and air in-leakage. Tube fouling 

leads to reduced heat transfer rates, 

while air in-leakage directly increases 

the backpressure of the condenser and 

degrades the quality of the water. 

Condenser tube cleaning can be 

performed using either on-line methods 

or more rigorous off-line methods. A full 

economic analysis should be performed 

to determine which off-line cleaning 

method is to be used. Such an analysis 

would result in an optimum offline or 

reduced-load cleaning schedule that 

could average between two and three 

cleanings a year. These analyses 

consider inputs such as operating data, 

plant performance, loads, time of year, 

etc., to accurately assess cleaning 

schedules for optimum economic 

performance. 

3. Cost of HRI 

a. Reasonableness of Cost 

As mentioned earlier, under CAA 

section 111(a)(1), EPA is required to 

determine ‘‘the best system of emission 

reduction which (taking into account 

the cost . . .) . . . has been adequately 

demonstrated.’’ In several cases, the 

D.C. Circuit has elaborated on this cost 

factor in various ways, stating that EPA 

may not adopt a standard for which 

costs would be ‘‘exorbitant,’’ 20 ‘‘greater 

than the industry could bear and 

survive,’’ 21 ‘‘excessive,’’ 22 or 

‘‘unreasonable.’’ 23 These formulations 

appear to be synonymous and suggest a 

cost-reasonableness standard. Therefore, 

in this action, EPA has evaluated 


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24While some EGUs may not realize the full 

potential of cost recuperation from fuel savings, we 

expect that the net costs of implementing heat rate 

improvements as an approach to reducing CO2

emissions from fossil fuel-fired EGUs are 

reasonable. 25See page 21, ‘‘PSD and Title V Permitting 

Guidance for Greenhouse Gases,’’ EPA–457/B–11– 

001, March 2011; https://www.epa.gov/sites/ 

production/files/2015-12/documents/ghgpermitting

guidance.pdf. 

26See page 25, ‘‘Available and Emerging 

Technologies for Reducing Greenhouse Gas 

Emissions from Coal-fired Electric Generating 

Units,’’ October 2010; https://www.epa.gov/sites/ 

production/files/2015-12/documents/ 

electricgeneration.pdf. 

27 ‘‘Coal-Fired Power Plant Heat Rate Reductions’’ 

Sargent & Lundy report SL–009597 (2009) https:// 

www.epa.gov/sites/production/files/2015-08/ 

documents/coalfired.pdf. 

whether the costs of HRI are considered 

to be reasonable. 

Any efficiency improvement made by 

an EGU will also reduce the amount of 

fuel consumed per unit of electricity 

output; fuel costs can account for as 

much as 70 percent of production costs 

of power. The cost attributable to CO2

emission reductions, therefore, is the 

net cost of achieving HRIs after any 

savings from reduced fuel expenses. So, 

over some time period (depending 

upon, among other factors, the extent of 

HRIs, the cost to implement such 

improvements, and the unit utilization 

rate), the savings in fuel cost associated 

with HRIs may be sufficient to cover the 

costs of implementing the HRI 

measures. Thus, the net costs of HRIs 

associated with reducing CO2 emissions 

from affected EGUs can be relatively 

low depending upon each EGUs’ 

individual circumstances. It should be 

noted that this cost evaluation is not an 

attempt to determine the affordability of 

the HRI in a business or economic sense 

(i.e., the reasonableness of the imposed 

cost is not determined by whether there 

is an economic payback within a 

predefined time period). However, the 

ability of EGUs to recoup some of the 

costs of HRIs through fuel savings 

supports a finding that cost recovery is 

a reasonable factor in determining cost 

effectiveness.24

Most often, when evaluating costs for 

criteria pollutants—in a BACT analysis, 

for example—the emphasis is focused 

on the cost of control relative to the 

amount of pollutant removed—a metric 

typically referred to as the ‘‘costeffectiveness.’’ There have been 

relatively few BACT analyses evaluating 

GHG reduction technologies for coalfired EGUs; and, therefore not a large 

number of GHG cost-effectiveness 

determinations to compare against as a 

measure of the cost reasonableness. 

Nevertheless, in PSD and Title V 

permitting guidance for GHG emissions, 

EPA noted that ‘‘it is important in BACT 

reviews for permitting authorities to 

consider options that improve the 

overall energy efficiency of the source or 

modification—through technologies, 

processes and practices at the emitting 

unit. In general, a more energy efficient 

technology burns less fuel than a less 

energy efficient technology on a per unit 

of output basis.’’ 25 EPA has also noted 

that a ‘‘number of energy efficiency 

technologies are available for 

application to both existing and new 

coal-fired EGU projects that can provide 

incremental step improvements to the 

overall thermal efficiency.’’ 26

b. Cost of the HRI Candidate 

Technologies Measures 

The estimated costs for the BSER 

candidate technologies are presented 

below in Table 2. These are cost ranges 

from the 2009 S&L Study 27 updated to 

$2016. These costs correspond to ranges 

of HRI (percent) presented earlier in 

Table 1. 

TABLE 2—SUMMARY OF COST ($2016/KW) OF HRI MEASURES

HRI measure 

<200 MW 200–500 MW >500 MW 

Min Max Min Max Min Max 

Neural Network/Intelligent Sootblowers ... 4.7 4.7 2.5 2.5 1.4 1.4 

Boiler Feed Pumps .................................. 1.4 2.0 1.1 1.3 0.9 1.0 

Air Heater & Duct Leakage Control ......... 3.6 4.7 2.5 2.7 2.1 2.4 

Variable Frequency Drives ...................... 9.1 11.9 7.2 9.4 6.6 7.9 

Blade Path Upgrade (Steam Turbine) ..... 11.2 66.9 8.9 44.6 6.2 31.0 

Redesign/Replace Economizer ................ 13.1 18.7 10.5 12.7 10.0 11.2 

Improved O&M Practices ......................... Minimal capital cost. 

In the CPP, EPA estimated the 

potential national average net HRI by 

coal-fired EGUs to between 2.1 to 4.3 

percent for each interconnection, or 

about 4 percent nationally, with the 

improvements coming from some 

combination of best operating practices 

and equipment upgrades. The Agency 

noted in the CPP that the maximum cost 

of HRI from Table 2 is expected to be 

less than the $100/kW value used in the 

CPP proposal, especially as the EGU 

size increases; and, therefore, the 

Agency assessed the economic effects of 

HRI costs that might range from $50 to 

$100/kW. The technical applicability 

and efficacy of HRI measures and the 

cost of implementing them are 

dependent upon site specific factors and 

can vary widely from site to site. 

Because there is inherent flexibility 

provided to the states in applying the 

standards of performance, there is a 

wide range of potential outcomes that 

are highly dependent upon how the 

standards are applied (and to what 

degree states take into consideration 

other factors, including remaining 

useful life). 

In the RIA accompanying this 

proposal, the Agency evaluates three 

illustrative scenarios that recognize the 

inherent flexibility provided to states in 

applying standards of performance and 

provide insight on potential outcomes. 

For those illustrative scenarios, EPA 

evaluates costs ranging from $50/kW to 

$100/kW. EPA requests comment, with 

analysis, on other cost ranges that may 

be appropriate. 

4. Nonair Quality Health and 

Environmental Impacts, Energy 

Requirements, and Other Considerations 

As directed by CAA section 111(a)(1), 

EPA has taken into account nonair 

quality health and environment 

requirements, and energy requirements 

for each of the candidate BSER 

technologies listed in Tables 1 and 2. 

None of the candidate technologies, if 

implemented at a coal-fired EGU, would 

be expected to result in any deleterious 

effects on any of the liquid effluents 

(e.g., scrubber liquor) or solid byproducts (e.g., ash, scrubber solids). All 

of these candidate technologies, when 


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implemented, would have the effect of 

improving the efficiency of the coalfired EGUs to which they are applied. 

As such, the EGU would be expected to 

use less fuel to produce the same 

amount of electricity as it did prior to 

the efficiency (heat rate) improvement. 

None of candidate technologies is 

expected to impose any significant 

additional auxiliary energy demand. 

Implementation of heat rate 

improvement measures also would 

achieve reasonable reductions in CO2

emissions from affected sources in light 

of the limited cost-effective and 

technically feasible emissions control 

opportunities. In the same vein, because 

existing sources face inherent 

constraints that new sources do not, 

existing sources present different, and 

in some ways more limited, 

opportunities for technological 

innovation or development. 

Nevertheless, the proposed emissions 

guidelines encourage technological 

development by promoting further 

development and market penetration of 

equipment upgrades and process 

changes that improve plant efficiency. 

5. Potential HRI at Existing Coal-Fired 

EGUs 

Government agencies and 

laboratories, industry research 

organizations, engineering firms, 

equipment suppliers, and 

environmental organizations have 

conducted studies examining the 

potential for improving heat rate in the 

U.S. EGU fleet or a subset of the fleet. 

Table 3 below provides a list of some 

reports, case studies, and analyses about 

HRI opportunities in the United States. 

EPA is seeking comment on how these 

studies (and any others that the Agency 

should be aware of) can inform our 

understanding of potential HRI 

opportunities (Comment C–8). 

TABLE 3—HRI REPORTS, CASE STUDIES, AND ANALYSES

HRI report organization/publication (author, if known)—title—year [URL] 

Government Studies: 

Congressional Research Service (Campbell)—Increasing the Efficiency of Existing Coal-fired Power Plants (R43343)—2013 [https://fas.org/ 

sgp/crs/misc/R43343.pdf]. 

EIA—Analysis of Heat Rate Improvement Potential at Coal-Fired Power Plants—2015 [https://www.eia.gov/analysis/studies/powerplants/ 

heatrate/pdf/heatrate.pdf]. 

EPA—Greenhouse Gas Mitigation Measures—2015 [https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0602-37114]. 

NETL—Opportunities to Improve the Efficiency of Existing Coal-fired Power Plants—2009 [http://www.netl.doe.gov/File%20Library/ 

Research/Energy%20Analysis/Publications/OpportImproveEfficExistCFPP-ReportFinal.pdf]. 

NETL—Improving the Thermal Efficiency of Coal-Fired Power Plants in the United States—2010 [http://www.netl.doe.gov/File%20Library/ 

Research/Energy%20Analysis/Publications/ThermalEfficCoalFiredPowerPlants-TechWorkshopRpt.pdf]. 

NETL—Improving the Efficiency of Coal-Fired Power Plants for Near Term Greenhouse Gas Emissions Reductions (DOE/NETL–2010/ 

1411)—2010 [http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/DOE-NETL-2010-1411-ImpEfficCFPP

GHGRdctns-0410.pdf]. 

NETL—Options for Improving the Efficiency of Existing Coal-Fired Power Plants (DOE/NETL–2013/1611)—2014 [https://www.netl.doe.gov/ 

energy-analyses/temp/FY14_OptionsforImprovingtheEfficiencyofExistingCoalFiredPowerPlants_040114.pdf]. 

IEA (Reid)—Retrofitting Lignite Plants to Improve Efficiency and Performance (CCC/264)—2016 [http://bookshop.iea-coal.org/ 

reports/ccc-264/83861]. 

IEA (Henderson)—Upgrading and Efficiency Improvement in Coal-fired Power Plants (CCC/221)—2013 [http://bookshop.iea-coal.org/ 

reports/ccc-221/83186]. 

European Commission—Integrated Pollution Prevention and Control Reference Document on Best Available Techniques for Large 

Combustion Plants—2006 [http://eippcb.jrc.ec.europa.eu/reference/BREF/lcp_bref_0706.pdf]. 

Industry/Industrial Groups: 

EPRI—Range of Applicability of Heat Rate Improvements—2014 [https://www.epri.com/#/pages/product/000000003002003457]. 

ABB Power Generation—Energy Efficient Design of Auxiliary Systems in Fossil-Fuel Power Plants [https://library.e.abb.com/public/ 

5e627b842a63d389c1257b2f002c7e77/Energy%20Efficiency%20for%20Power%20Plant%20Auxiliaries-V2_0.pdf]. 

Alstom Engineering (Sutton)—CO2 Reduction Through Energy Efficiency in Coal-Fired Boilers—2011 [http://www.mcilvainecompany.com/ 

Universal_Power/Subscriber/PowerDescriptionLinks/Jim%20Sutton%20-%20Alstom%20-%203-31-2011.pdf]. 

GE—Comments of the General Electric Company—2014 [https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0602-22971]. 

National Petroleum Council—Electric Generation Efficiency—2007 [http://www.npc.org/Study_Topic_Papers/4-DTG-ElectricEfficiency.pdf]. 

S&L—Coal-fired Power Plant Heat Rate Reductions (SL–009597)—2009 [https://www.regulations.gov/document?D=EPA-HQ-OAR-2013- 

0602-36895]. 

S&L—Coal Fired Power Plant Heat Rate Reduction—NRECA (SL–012541)—2014 [https://www.regulations.gov/document?D=EPA-HQOAR-2013-0602-22767 Supp 33]. 

Storm Technologies—Applying the Fundamentals for Best Heat Rate Performance of Pulverized Coal Fueled Boilers—2009 [http://

www.stormeng.com/pdf/EPRI2009HeatRateConference%20FINAL.pdf]. 

Environmental Groups/Academic Studies: 

Lehigh University—Reducing Heat Rates of Coal-fired Power Plants—2009 [http://www.lehigh.edu/∼inenr/leu/leu_61.pdf]. 

NRDC—Closing the Power Plant Carbon Pollution Loophole: Smart Ways the Clean Air Act Can Clean Up America’s Biggest Climate 

Polluters (12–11–A)—2013 [https://www.nrdc.org/sites/default/files/pollution-standards-report.pdf]. 

Resources for the Future (Lin et al.)—Regulating Greenhouse Gases from Coal Power Plants Under the Clean Air Act (RFF–DP–13–05)— 

2014 [http://www.rff.org/files/sharepoint/WorkImages/Download/RFF-DP-13-05.pdf]. 

Sierra Club (Buckheit & Spiegel)—Sierra Club 52 Unit Study—2014 [http://content.sierraclub.org/environmentallaw/sites/ 

content.sierraclub.org.environmentallaw/files/Appendix%201%20-%20Rate%20v%20Load%20Summary.pdf]. 

Other Publications: 

Power Engineering International (CoX)—Dry Sorbent Injection for SOX Emissions Control—2017 [http://www.powerengineeringint.com/ 

articles/print/volume-25/issue-6/features/dry-sorbent-injection-for-sox-emissions-control.html]. 

Power Mag (Korellis)—Coal-Fired Power Plant Heat Rate Improvement Options, Parts 1 & 2—2014 [http://www.powermag.com/coal-firedpower-plant-heat-rate-improvement-options-part-2] [http://www.powermag.com/coal-fired-power-plant-heat-rate-improvement-options-part1]. 

Power Mag (Peltier)—Steam Turbine Upgrading: Low-hanging Fruit—2006 [http://www.powermag.com/steam-turbine-upgrading-lowhanging-fruit]. 


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28Phillips, J.; Levine, P.; ‘‘Gas Turbine 

Performance Upgrade Options’’, FERN Engineering 

Paper, available at http://www.fernengineering.com/ 

pdf/gt_upgrade_options.pdf. 

29CCS is sometimes referred to as Carbon Capture 

and Sequestration. It is also sometimes referred to 

as CCUS or Carbon Capture Utilization and Storage 

(or Sequestration), where the captured CO2 is 

utilized in some useful way and/or permanently 

stored (for example, in conjunction with enhanced 

oil recovery). In this document, we consider these 

terms to be interchangeable and for convenience 

will exclusively use the term CCS. 

It has been noted that unit-level HRIs, 

with the resulting reductions in variable 

operating costs at those improved EGUs, 

could lead to increases in utilization of 

those EGUs as compared to other 

generating options (i.e., ‘‘rebound 

effect’’). See generally 80 FR 64745. 

As part of the cost-benefit analysis in 

the RIA for this proposed action, EPA 

modeled a range of potential HRIs 

(percent improvement, as described in 

the RIA). The results of the modeling, 

for the years of analysis for this rule, 

predict that there will be no cumulative 

increases in system-wide emissions 

relative to a scenario where no action is 

taken. While the RIA shows that, under 

certain assumptions, sources that adopt 

HRI may increase generation, due to 

their improved efficiency and relatively 

improved economic competitiveness, 

they also generally reduce emissions (as 

a group) because they can generate 

higher levels of electricity with a lower 

overall emission rate. Hence, EPA 

analysis indicates that the system-wide 

emission decreases due to reduced heat 

rate are likely to be larger than any 

system-wide increases due to increased 

operation. EPA solicits comment on this 

conclusion (Comment C–9). 

C. HRI for Natural Gas-Fired Stationary 

Combustion Turbines 

EPA has also considered 

opportunities for emission reductions at 

natural gas-fired stationary combustion 

turbines as a part of the BSER—at both 

simple cycle turbines and combined 

cycle turbines—and previously 

determined that the available emission 

reductions would likely be expensive or 

would likely provide only small overall 

reductions relative to those that were 

predicted through application of other 

systems of emission reduction identified 

in the CPP building blocks. In the 

development of the CAA section 111(b) 

standards of performance for new, 

modified, and reconstructed EGUs, 

several commenters provided 

information on options that may be 

available to improve the efficiency of 

existing natural gas-fired stationary 

combustion turbines. See 80 FR 64620. 

Commenters—including turbine 

manufacturers—described specific 

technology upgrades for the compressor, 

combustor, and gas turbine components 

that operators of existing combustion 

turbines may deploy. The commenters 

noted that these state-of-the-art gas path 

upgrades, software upgrades, and 

combustor upgrades have the potential 

to reduce GHG emissions by a 

significant amount. In addition, one 

turbine manufacturer stated that 

existing combustion turbines can 

achieve the largest efficiency 

improvements by upgrading existing 

compressors with more advanced 

compressor technologies, potentially 

improving the combustion turbine’s 

efficiency by an additional margin. See 

80 FR 64620. 

In addition to upgrades to the 

combustion turbine, the operator of a 

NGCC unit may have the opportunity to 

improve the efficiency of the heat 

recovery steam generator and steam 

cycle using retrofit technologies that 

may reduce the GHG emissions by 1.5 

to 3 percent. These include: (1) Steam 

path upgrades that can minimize 

aerodynamic and steam leakage losses; 

(2) replacement of the existing highpressure turbine stages with state-of-theart stages capable of extracting more 

energy from the same steam supply; and 

(3) replacement of low-pressure turbine 

stages with larger diameter components 

that extract additional energy and that 

reduce velocities, wear, and corrosion. 

In the ANPRM, EPA requested 

comment on the broad availability and 

applicability of any HRIs for natural gas 

combustion turbine EGUs. EPA also 

solicited comment on the Agency’s 

previous determination in the CPP that 

the available GHG emission reduction 

opportunities would likely provide only 

small overall GHG reductions as 

compared to those from HRIs at existing 

coal-fired EGUs. See 80 FR 64756. 

Several commenters suggested that 

there are significant opportunities for 

emission reductions via HRIs at natural 

gas combined cycle EGUs while many 

other commenters contended that any 

such emission reductions would be 

minimal and too expensive. Still, other 

commenters noted that operational 

changes—such as lower capacity factor 

or fluctuations in load (cycling)—affect 

the heat rate and make it difficult to 

accurately gauge the availability of HRI 

opportunities for NGCC EGUs. 

However, while numerous comments 

suggested that there are available HRI 

opportunities at existing NGCC EGUs, 

no commenters provided specific 

information on the availability, 

applicability, or cost of HRI 

opportunities for NGCC units—nor did 

any commenters provide any 

information on the magnitude of 

expected heat rate reductions. 

To assess potential HRI of existing 

NGCC EGUs, EPA looked at 11 years of 

historical gross heat rate data from 2007 

to 2017 for existing NGCC EGUs that 

reported both heat input and gross 

electricity output to the Agency in 2017. 

The Agency used the 2007 to 2016 data 

to calculate a ‘‘benchmark’’ heat rate for 

each unit. EPA evaluated the HRI 

potential using an approach that is 

similar to the method used to determine 

a unit-specific standard that was 

finalized for modified coal-fired EGUs. 

The Agency evaluated the HRI potential 

by comparing the 2017 national annual 

heat rate with the best annual heat rate 

in the years from 2007 to 2016 year. The 

HRI potential was calculated nationally 

and at each regional interconnection: 

East, West, and Texas. Nationally the 

HRI evaluation suggested an average 

HRI potential of 3.4 percent. 

EPA also conducted a literature 

search and found some papers 

suggesting potential for improvement in 

the heat rate. The literature suggested 

that most HRIs would be accompanied 

by commensurate capacity increases.28

EPA takes comment on the estimates in 

this paper and is seeking any other 

information commenters have about the 

performance and cost of potential HRIs 

for turbines (Comment C–10). We also 

take comment on whether if EPA 

determined that HRIs in that range were 

available for similar costs, it would be 

appropriate for EPA to reconsider its 

determination that there are no HRIs 

that represent the BSER (Comment C– 

11). 

D. Other Considered Systems of GHG 

Emission Reductions 

EPA also considered other systems of 

GHG emission reductions that may be 

applied to affected EGUs but is not 

proposing that they should be part of 

the BSER for the reasons discussed 

below. EPA acknowledges that there 

may be other methods and technologies 

suitable for adoption at some specific 

sources, but states and sources are best 

suited to determine if those alternative 

measures and technologies are 

appropriate and/or allowable 

compliance measures. 

1. Carbon Capture and Storage (CCS) 29

EPA has previously determined that 

CCS (or partial CCS) should not be a 

part of the BSER for existing fossil fuelfired EGUs because it was significantly 

more expensive than alternative options 

for reducing emissions and may not be 

a viable option for many individual 

facilities. See 80 FR 64756. Even 

assuming that CAA section 111(d) may 

be used to project technological 


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30https://www.netpower.com/. 

31 In addition to new pipeline infrastructure, 

conversion to natural gas co-firing in a coal-fired 

boiler typically involves installation of new gas 

burners and supply piping, modifications to 

combustion air ducts and control dampers, and 

possibly modifications to the boiler’s steam 

superheater, reheater, and economizer heating 

surfaces that transfer heat from the hot flue gas 

exiting the boiler furnace. The conversion may also 

involve modification and possible deactivation of 

some downstream air pollution emission control 

equipment. 

advances, EPA must balance innovative 

technologies against their economic, 

energy, nonair health and 

environmental impacts. EPA continues 

to believe that neither CCS nor partial 

CCS are technologies that can be 

considered the BSER for existing fossil 

fuel-fired EGUs. However, if there is any 

new information regarding the 

availability, applicability, costs, or 

technical feasibility of CCS 

technologies, commenters are 

encouraged to provide that information 

to EPA (Comment C–12). 

Similarly, EPA considered whether 

CCS or partial CCS should be the BSER 

for natural gas-fired stationary 

combustion turbines and have 

determined that, currently, the 

technology is exorbitantly expensive, 

has not been adequately demonstrated, 

and would not be available for a large 

number of existing sources. Similar 

technologies—such as use of the novel 

Allam Cycle 30—are, while seemingly 

promising, still in the early 

demonstration phase. 

2. Fuel Co-Firing 

EPA has previously determined that 

co-firing of alternative fuels (biomass or 

natural gas) in coal-fired utility boilers 

is not part of BSER for existing fossil 

fuel-fired sources due to cost and 

feasibility considerations. See 80 FR 

64756. Although some fuel co-firing 

methods are technically feasible for 

some affected sources, there are factors 

and considerations that prevent its 

inclusion as BSER. In general, fuel use 

opportunities are dependent upon many 

regional considerations and 

characteristics (e.g., access to biomass, 

or natural gas pipeline infrastructure 

limitations), that prevent its adoption as 

BSER on a national level (whereas 

nearly all sources can or have 

implemented some form of heat rate 

improvement measures). Another 

important factor is cost, and broader 

application of fuel co-firing methods has 

been shown to be costly. While this 

proposal does not include fuel co-firing 

methods as BSER, EPA proposes that 

they be allowed as compliance options 

that states may consider (see Section 

VI). EPA solicits comment, nevertheless, 

on whether co-firing methods should be 

included among the list of BSER 

candidate technologies for states to 

evaluate when establishing a standard of 

performance for each affected source in 

their jurisdiction. 

a. Natural Gas Co-Firing 

Coal-fired power plants typically use 

natural gas or other clean fuel (such as 

low sulfur fuel oil) for start-up 

operations and, if needed, to maintain 

the unit in ‘‘warm stand-by.’’ Some 

plants co-fire natural gas simultaneously 

with coal—either directly as a 

combustion fuel or in configuration 

referred to as natural gas reburn, which 

is used for NOx control. During periods 

of natural gas co-firing, an EGU’s CO2

emission rate is reduced as natural gas 

is a less carbon intensive fuel than coal. 

For example, at 10 percent natural gas 

co-firing, the net emissions rate (lb/ 

MWh-net) of a typical unit would 

decrease by approximately 4 percent. 

On the other hand, co-firing can 

negatively impact a unit’s efficiency due 

to the high hydrogen content of natural 

gas and the resulting production of 

water as a combustion by-product. And 

depending on the design of the boiler 

and extent of modifications, some 

boilers may be forced to de-rate (a 

reduction in generating capacity) in 

order to maintain steam temperatures at 

or within design limits, or for other 

technical reasons. 

In evaluating BSER technology 

options, CAA section 111(a)(1) directs 

EPA to take into account nonair quality 

health and environmental impacts, and 

energy requirements. EPA is unaware of 

any significant nonair quality health or 

environmental impacts associated with 

natural gas co-firing. However, in taking 

energy requirements into account, EPA 

notes that co-firing natural gas in coalfired utility boilers is not the best, most 

efficient use of natural gas and, as noted 

above, can lead to inefficient operation 

of utility boilers. NGCC stationary 

combustion turbine units are much 

more efficient at using natural gas as a 

fuel for the production of electricity and 

it would not be an environmentally 

positive outcome for utilities and 

owner/operators to redirect natural gas 

from the more efficient NGCC EGUs to 

the less efficient coal-fired EGUs in 

order to satisfy an emission standard at 

the coal-fired unit. 

Moreover, unlike coal, natural gas 

cannot be stored in quantities sufficient 

for sustained utilization on site. 

Accordingly, delivery of natural gas via 

pipeline is essential for using natural 

gas at coal-fired EGUs. Many existing 

coal-fired plants, however, do not have 

access to natural gas transportation 

infrastructure and gaining access would 

be either infeasible (due to technical or 

timing considerations) or unreasonably 

costly.31 For plants that currently co-fire 

natural gas and have access to an 

existing natural gas pipeline, many may 

be capacity constrained (i.e., they are 

not able to greatly increase purchase 

volumes with the existing 

infrastructure). Accordingly, although 

natural gas fuel prices are currently low 

and some sources currently co-fire 

natural gas, on balance, there are 

notable challenges and concerns with 

instituting natural gas co-firing on a 

wide variety of units across the country. 

Therefore, EPA is not proposing that 

natural gas co-firing should be part of 

the BSER. 

b. Co-Firing Biomass 

The infrastructure, proximity and cost 

aspects of co-firing biomass at existing 

coal EGUs are similar in nature and 

concept to those of natural gas. While 

there are some existing coal-fired EGUs 

that currently co-fire with biomass fuel, 

those are in relatively close proximity to 

cost-effective biomass supplies; and, 

there are regional supply and demand 

dynamics at play. As with the other 

emission reduction measures discussed 

in this section, EPA expects that use of 

some types of biomass may be 

economically attractive for certain 

individual sources. However, on a 

broader scale, biomass co-firing is more 

expensive and/or less achievable than 

the measures determined to be part of 

the BSER. As such, EPA is not 

proposing that the use of biomass fuels 

is part of the BSER because too few 

individual sources will be able to 

employ that measure in a costreasonable manner. 

VI. State Plan Development 

A. Establishing Standards of 

Performance 

1. Application of the BSER 

As discussed in Section III above, 

EPA has the authority to determine the 

BSER as part of regulations it 

promulgates pursuant to CAA section 

111(d)(1) (providing that states shall 

submit plans to EPA establishing 

‘‘standards of performance’’ for existing 

sources); see also CAA section 111(a)(1) 

(defining ‘‘standard of performance’’ 

with reference to the ‘‘best system of 

emission reduction which . . . the 

Administrator determines has been 

adequately demonstrated’’). For such 

regulations, EPA has traditionally 

promulgated emission guidelines 

governing the process for states to 


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32This is consistent with the statutory definition 

of ‘‘standard of performance’’ at CAA section 

111(a)(1) (emphases added): ‘‘a standard for 

emissions of air pollutants which reflects the degree 

of emission limitation achievable through the 

application of the best system of emission reduction 

which (taking into account the cost of achieving 

such reduction and any nonair quality health and 

environmental impact and energy requirements) the 

Administrator determines has been adequately 

demonstrated.’’ 

submit plans which establish standards 

of performance which reflect the degree 

of emission limitation achievable 

through application of the BSER to each 

affected source within the state, in 

addition to the implementing 

regulations EPA initially promulgated in 

1975 to set the general framework under 

which it would administer section 

111(d). The implementing regulations 

that are also being proposed in this 

action (see Section VII below for a 

discussion on the proposed new 

implementing regulations) contain 

certain requirements for EPA in 

promulgating an emission guideline 

under section 111(d). One requirement 

of the new proposed implementing 

regulations (consistent with the 

previous implementing regulations and 

section 111(d) of the CAA) is that an 

EPA-promulgated emission guideline 

provide information on the degree of 

emission reduction which is achievable 

with each system, together with 

information on the costs, and nonair 

health and environmental effects, and 

energy requirements of applying each 

system to designated facilities.32 This 

means that EPA will provide, in 

addition to the BSER, information on 

the degree of emission reduction that is 

achievable when the BSER is applied. In 

the case of this proposed rulemaking 

and as described above in Section V, 

EPA is proposing that the BSER is HRI 

made at the unit level. To meet the 

requirements of the new proposed 

implementing regulations, EPA is 

proposing candidate technologies for 

HRI measures corresponding to a range 

of reductions and costs as information 

regarding the degree of emission 

reduction achievable through 

application of the BSER. Because 

affected EGUs in each state are different 

and the application of different HRI 

measures may take into account sourcespecific factors, EPA is providing 

expected ranges of HRIs. These ranges 

are shown in Table 1. 

EPA expects that states can use the 

information that EPA provides on the 

degree of emission limitation in 

developing standards of performance for 

affected EGUs as part of establishing a 

standard of performance for inclusion in 

a state’s plan pursuant to the 

requirements of section 111(d)(1). In 

this case, the ranges of HRIs are 

provided as guidance for states to use in 

evaluating the efficacy of implementing 

each measure identified as part of the 

BSER candidate technologies at each 

affected EGU. While the HRI potential 

range is provided as guidance for the 

states, the actual HRI performance for 

each of the candidate technologies will 

be unit-specific and will depend upon 

a range of unit-specific factors. The 

states will use the information provided 

by EPA as guidance, but will be 

expected to conduct unit-specific 

evaluations of HRI potential, technical 

feasibility, and applicability for each of 

the BSER candidate technologies. Once 

a state evaluates the HRIs identified as 

part of the BSER in establishing a 

standard of performance for a particular 

affected EGU, it is within the state’s 

discretion to take certain factors 

concerning that source, such as 

remaining useful life, into consideration 

when determining how the standard of 

performance should be applied. The 

next section describes how states may 

derive a standard of performance 

reflecting the degree of emission 

limitation achievable through 

application of the BSER. 

Additionally, the new proposed 

implementing regulations require that 

an emission guideline identify 

information such as a timeline for 

compliance with standards of 

performance that reflect the application 

of the BSER. See proposed 40 CFR 

60.22a. However, given the sourcespecific nature of this proposed 

emission guideline and reasonably 

anticipated variation between standards 

established for sources within a state, 

EPA believes it more appropriate that a 

state establish tailored compliance 

deadlines for its sources based on the 

standard ultimately determined for each 

source. Accordingly, the EPA proposes 

to supersede this aspect of proposed 40 

CFR 60.22a, as allowed under the 

applicability provision under proposed 

60.20a, and allow for states to include 

appropriate compliance deadlines for 

sources based on the standards of 

performance determined as part of the 

state plan process. 

EPA is proposing, consistent with the 

new proposed implementing regulations 

(subpart Ba), that states will include 

custom compliance schedules for 

affected EGUs as part of their state plan. 

This is another area that states have 

latitude for taking into account unit 

specific factors. It should be noted 

however, that per the proposed new 

implementing regulations, if a state 

chooses to include a compliance 

schedule for a source that extends more 

than twenty-four months from the 

submittal of the state plan, the plan 

must also include legally enforceable 

increments of progress for that source 

(See proposed 40 CFR 60.24a(d)(1)). The 

EPA solicits comment on whether states 

should determine source-specific 

compliance schedules under this 

emission guideline, or if a uniform 

compliance schedule is appropriate, and 

if so, what length of time is appropriate. 

(Comment C–13). 

2. Determination of a Unit’s Standard of 

Performance 

As described in other parts of this 

section, while EPA’s role is to determine 

the BSER, section 111(d)(1) squarely 

places the responsibility of establishing 

a standard of performance for an 

existing source on the state as part of 

developing a state plan. EPA is 

proposing that once EPA determines the 

BSER, states are expected to evaluate 

each of the BSER HRI measures that 

EPA has determined represent BSER in 

establishing a standard of performance 

for each source within their jurisdiction. 

The states, in applying the standards of 

performance, may take into 

consideration, among other factors, the 

remaining useful life of the existing 

source to which the standard would 

apply (see Section VI.B.1 for further 

discussion on remaining useful life and 

other factors). The proposed BSER is a 

list of candidate technologies that are 

HRI measures, which states should 

evaluate, and potentially apply to 

existing sources as appropriate based 

upon the specific characteristics of 

those units. In general, EPA envisions 

that, under the proposed program, the 

states would set standards based on 

considerations most appropriate to 

individual sources or groups of sources 

(e.g., subcategories). These may include 

consideration of historical emission 

rates, effect of potential HRIs (informed 

by the information in EPA’s candidate 

technologies described earlier in Section 

V), or changes in operation of the units, 

among other factors the state believes 

are relevant. As such, states have 

considerable flexibility in determining 

emission standards for units, as 

contemplated by the express statutory 

text. 

Several commenters on the ANPRM 

suggested that EPA should develop a 

default methodology for determining 

appropriate standards of performance 

that are consistent with the BSER. More 

specifically, commenters suggested that 

EPA should use a methodology that is 

similar to the one finalized for major 

modifications at coal-fired EGUs under 

the section 111(b) program—i.e., based 

on the use of historical heat rate or 

emissions data for the individual 


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source. Commenters also suggested that 

any approach covering all existing units 

should use at least ten years’ worth of 

historical data and should be based on 

rolling averages for multiple year 

periods (e.g., the fourth highest threeyear average during the historical lookback period). Other commenters 

suggested that the approach used for 

major modifications was too stringent to 

apply to all units. EPA understands that 

if the Agency were to provide a specific 

and presumptively-approvable 

methodology for establishing standards 

of performance, that approach would 

provide states with certainty in how to 

develop plans. EPA is not proposing a 

specific methodology or formula for 

establishing standards of performance 

for existing sources in this action. EPA 

believes that such a presumptive 

standard could be viewed as limiting a 

state’s ability to deviate from the 

prescribed methodology and that the 

approach could ultimately be more 

limiting than helpful. While EPA is not 

proposing a presumptive formulaic 

approach in this action, the Agency is 

soliciting comment on approaches based 

on the use of historical heat rate or 

emissions data for the individual source 

(Comment C–14). The circumstances 

and considerations for establishing 

standards of performance under CAA 

111(b) for affected sources that have 

undergone a modification (i.e., any 

physical change in or change in the 

method of operation that increases the 

hourly emissions of GHG) are not the 

same as the circumstances and 

considerations for states should take 

into account in establishing standards of 

performance under these proposed 

emission guidelines, but there are 

certainly parallels and similarities. 

As mentioned earlier, states may take 

into consideration other factors, 

including remaining useful life, when 

applying unit-specific standards of 

performance. Consideration of these 

factors may result in the application of 

the standard of performance in a less 

stringent manner than would otherwise 

be suggested by strict implementation of 

the BSER technologies. This topic is 

discussed in detail in Section VI.B. 

As previously described, this proposal 

seeks to clarify the Agency’s and states’ 

roles under section 111(d). The statute 

is clear that EPA determines the BSER, 

and states submit plans that establish 

standards of performance for existing 

sources that, under the definition of 

‘‘standard of performance in CAA 

section 111(a)(1), reflect the degree of 

emission limitation achievable though 

the application of the BSER. Consistent 

with the statute, EPA’s proposed 

implementing regulations at 40 CFR 

60.22a(b)(2) specify that an emission 

guideline must include information on 

the degree of emission reduction which 

is achievable, but does not require that 

EPA must provide a standard of 

performance that presumptively reflects 

such degree of emission reduction 

which is achievable through application 

of the BSER, as that is appropriately the 

states’ role. EPA is proposing to clarify 

that the implementing regulations do 

not require EPA to provide a 

presumptive numerical standard as part 

of its emission guidelines and that the 

ranges of expected emission reductions 

that can be achieved in EPA’s BSER 

determination adequately provide 

sufficient information to the states on 

the degree of emission limitation that 

will result from application of the BSER 

to existing sources to appropriately 

inform the states’ exercise of their 

authority to develop plans under 111(d). 

Given that section 111(d)(1) requires 

states to submit plans that establish 

standards of performance for affected 

sources, EPA believes it is consistent 

with the spirit of cooperative federalism 

to provide information sufficient to 

assist states in the development of state 

plans, which in turn will provide both 

states and sources with regulatory 

certainty via a plan that is approvable 

under section 111(d)(2) and applicable 

regulations. As mentioned above, EPA is 

proposing to provide information 

regarding ranges of expected reductions 

associated with the various HRIs 

identified as the BSER, which will assist 

states in establishing appropriate 

standards of performance for affected 

EGUs. EPA proposes to determine 

providing such information is consistent 

with both the implementing regulations 

at 40 CFR 60.22(b) and CAA section 

111(d) regarding the roles of states and 

EPA determining the degree of emission 

limitation achievable through 

application of the BSER. 

As described below in Section VI.B, 

under the statute, the proposed new 

implementing regulations, and these 

proposed emission guidelines, states 

have considerable flexibility in 

developing their plans and establishing 

and applying standards of performance 

to existing sources. One of the areas of 

flexibility described is in the standard 

setting process for EGUs. As part of this 

flexibility, EPA is proposing that states 

should have broad flexibility on 

whether and how the state chooses to 

group, sort, or subcategorize affected 

EGUs within the state to establish 

standards of performance. In evaluating 

affected EGUs, if a state finds that there 

is an overlap in circumstances around a 

group of EGUs, it might make sense to 

implement a uniform methodology for 

setting a standard of performance across 

that group. Another area of flexibility is 

explicitly provided in the statutory text 

of 111(d)(1) itself. The statute requires 

that EPA’s regulations implementing 

section 111(d) shall permit the State in 

applying a standard of performance to 

any particular source under a plan 

submitted under this paragraph to take 

into consideration, among other factors, 

the remaining useful life of the existing 

source to which such standard applies. 

3. Forms of Standards of Performance 

As described further in Section VII.C 

of this preamble, EPA is proposing a 

new implementing regulation for 

section 111(d) which includes a 

proposed definition of ‘‘standard of 

performance that aligns with the 

statutory definition of the term under 

CAA section 111(a)(1). EPA is further 

proposing, as part of the new 

implementing regulations, that a 

specific emission guideline may contain 

provisions that supersede the 

applicability of the implementing 

regulations. In the context of these 

emission guidelines, EPA is proposing 

that an allowable emission rate (i.e., 

rate-based standard in, for example, lb 

CO2/MWh-gross) be the form of 

standard of performance that states 

would include in their state plans for 

affected EGUs. Primarily, an allowable 

emission rate most closely aligns to 

EPA’s BSER determination for these 

emission guidelines. When HRIs are 

made at an EGU, by definition, the CO2

emission rate will decrease as described 

above in Section V.B. There is a natural 

correspondence between the BSER and 

an allowable emission rate as the 

standard of performance in this action. 

Secondly, EPA is proposing that state 

plans include only the one form of 

standard of performance (i.e., proposing 

only an allowable emission rate) to 

create continuity across states, prevent 

ambiguity, and to ensure as much 

simplicity as possible. However, EPA 

solicits comment on whether other 

forms of standards of performance 

should be allowed in state plans and 

whether a different form of standard 

should be the primary form that is 

authorized for state plans under a final 

emission guideline in response to this 

proposal (Comment C–15). 

EPA is proposing an allowable 

emission rate of CO2 as the form of the 

standard of performance because it 

creates the most straightforward system 

for states to determine standards and 

ensure compliance. This also creates a 

more streamlined evaluation for EPA to 

consider in state plan evaluation as 

there are fewer variables to consider 

(e.g., projections of utilization which 


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33EPA believes that biomass co-firing can meet 

the two criteria above because the biomass can be 

burned at the source and there are different 

methods that can be used to monitor or calculate 

the amount of biogenic CO2 emissions associated 

with biomass use at a unit. 

would be required if the standard of 

performance took a mass-based form). 

4. Gross Versus Net Emission Standards 

EPA also requests comment on the 

merits of differentiating between gross 

and net heat rate (Comment C–16). This 

may be particularly important when 

considering the effects of part load 

operations (i.e., net heat rate would 

include inefficiencies of the air quality 

control system at a part load whereas 

gross heat rate would not). This will 

also be important in recognizing the 

improved efficiency obtained from 

upgrades to equipment that reduce the 

auxiliary power demand. 

B. Flexibilities for States and Sources 

Once EPA determines the BSER, 

section 111(d)(1) of the CAA requires 

that ‘‘each State shall submit to the 

Administrator a plan which (A) 

establishes standards of performance for 

any existing source [. . .], and (B) 

provides for the implementation and 

enforcement of such standards of 

performance.’’ Section 111(d)(1) further 

requires EPA to ‘‘permit the State in 

applying a standard of performance to 

any particular source under a plan 

[. . .] to take into consideration, among 

other factors, the remaining useful life 

of the existing source to which such 

standard applies.’’ 

In light of the cooperative-federalist 

structure of section 111(d) and its 

express language requiring that EPA 

allow states to take into account sourcespecific factors when establishing 

standards of performance for existing 

sources, EPA believes it is appropriate 

in this proposal to provide considerable 

flexibility for states to set standards of 

performance for units and also allow 

states to have considerable latitude for 

implementing measures and standards 

for affected EGUs. A detailed discussion 

of the flexibility that states have in 

developing standards of performance is 

provided below in Section VI.B.1. States 

also have flexibility in the measures and 

processes that they put in place for 

affected EGUs to meet their compliance 

obligations. One of the examples of this 

is discussed in Section VI.B.2 on 

averaging and trading. As previously 

discussed, the BSER’s candidate 

technologies affords states considerable 

flexibility to determine how to apply 

standards of performance to affected 

sources. Several commenters noted in 

the ANPRM that flexibility for States 

and affected sources should be part of 

any replacement rule, with States being 

able to choose from a wide variety of 

possible methods for developing a 

standard of performance, along with 

options for how to implement the 

standard through their state plans. Other 

commenters suggested that any flexible 

compliance opportunities provided 

should be directly linked to the 

determination of the BSER, such that 

increased compliance flexibility in the 

state’s establishment of a standard of 

performance for an existing source can 

only be included to the extent that the 

flexibility is included as part of the 

BSER. 

Another important and distinctly 

different element of flexibility in this 

proposal is the availability of 

compliance options for affected sources 

in meeting their standards of 

performance. To the extent that a state 

develops a standard of performance for 

an affected source within its 

jurisdiction, the state is free to give the 

source flexibility to meet that standard 

of performance using either BSER 

technologies or some other non-BSER 

technology or strategy. In other words, 

an affected source may have broad 

discretion in meeting its standard of 

performance within the requirements of 

a state’s plan. For example, there are 

technologies, methods, and/or fuels that 

can be adopted at the affected source to 

allow the source to comply with its 

standard of performance that were not 

determined to be the BSER, but which 

may be applicable and prudent for 

specific units to use to meet their 

compliance obligations. Examples of 

non-BSER technologies and fuels 

include HRI technologies that were not 

included as candidate technologies, 

CCS, and fuel co-firing (natural gas or 

certain biomass). In keeping with past 

programs that regulated affected sources 

using a standard of performance, EPA 

takes no position regarding whether 

there may be other methods or 

approaches to meeting such a standard, 

since there are likely various 

approaches to meeting the standard of 

performance that EPA is either unable to 

include as part of the BSER, or is unable 

to predict. EPA proposes that affected 

sources may use both BSER and nonBSER measures to achieve compliance 

with their state plan obligations. 

To demonstrate that measures taken 

to meet compliance obligations for a 

source actually reduce its emission rate, 

EPA proposes that the measures should 

meet two criteria: (1) They are 

implemented at the source itself, and (2) 

they are measurable at the source of 

emissions using data, emissions 

monitoring equipment or other methods 

to demonstrate compliance, such that 

they can be easily monitored, reported 

and verified at a unit. There may be 

other technologies or compliance 

measures that meet these general 

criteria. EPA solicits comment on 

whether these two criteria are 

appropriate or not and why, and 

whether there may be compliance 

flexibilities that might meet the two 

proposed criteria (Comment C–17). This 

proposed rule is intended to generally 

allow compliance flexibility in state 

plans where appropriate, to the extent 

they contribute to meeting any 

particular standard of performance, 

consistent with the criteria. EPA is 

further soliciting comment on whether 

there are certain non-BSER measures 

that should be disallowed for 

compliance, and if so, under what 

criteria or rationale should measures be 

disallowed for compliance (Comment 

C–18). 

Section 111(d)(1)(B) additionally 

requires state plans to include measures 

that provide for the implementation and 

enforcement of standards of 

performance. EPA believes states can 

meet these requirements by including 

measures as described in Section VI.C of 

this proposal regarding state plan 

components, such as monitoring, 

reporting, and recordkeeping 

requirements. EPA solicits comments on 

what other implementation and 

enforcement measures may be necessary 

for states to meet the requirements of 

section 111(d)(1)(B) (Comment C–19). 

Additionally, as part of ensuring that 

regulatory obligations appropriately 

meet statutory requirements such as 

enforceability, EPA has historically and 

consistently required that obligations 

placed on sources be quantifiable, nonduplicative, permanent, verifiable, and 

enforceable. EPA is similarly proposing 

that standards of performance places on 

affected EGUs as part of a state plan be 

quantifiable, non-duplicative, 

permanent, verifiable, and enforceable. 

The Agency specifically recognizes 

that some entities may be interested in 

using biomass as a compliance option 

for meeting the state determined 

emission standard.33 As with the other 

non-BSER measures discussed in this 

section, EPA expects that use of biomass 

may be economically attractive for 

certain individual sources even though 

on a broader scale it may be more 

expensive or less achievable than the 

measures determined to be part of the 

BSER (and therefore EPA is not 

proposing to determine that it should be 

included within the BSER, which is 

properly limited to measures likely to be 

cost-reasonable for a greater proportion 


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34https://www.epa.gov/sites/production/files/ 

2018-04/documents/biomass_policy_statement_

2018_04_23.pdf. 

35This policy statement aligns with provisions in 

the Consolidated Appropriations Act, 2018, which 

calls for EPA, the Department of Energy and the 

Department of Agriculture to establish policies that, 

consistent with their missions, jointly ‘‘reflect the 

carbon-neutrality of forest bioenergy and recognize 

biomass as a renewable energy source, provided the 

use of forest biomass for energy production does not 

cause conversion of forests to non-forest use.’’ 

https://www.congress.gov/115/bills/hr1625/BILLS115hr1625enr.pdf. 

of existing sources than we believe 

biomass to be at this time). 

Certain kinds of biomass, including 

that from managed forests, have the 

potential to offer a wide range of 

economic and environmental benefits, 

including carbon benefits. However, 

these benefits can typically only be 

realized if biomass feedstocks are 

sourced responsibly, which can include 

ensuring that forest biomass is not 

sourced from lands converted to nonforest uses. States that intend to propose 

the use of forest-derived biomass for 

compliance by affected units may refer 

to EPA’s April 2018 statement on its 

intended treatment of biogenic CO2

emissions from stationary sources that 

use forest biomass for energy 

production.34 35 As discussed in the 

recent statement, EPA’s policy is to treat 

biogenic CO2 emissions resulting from 

the combustion of biomass from 

managed forests at stationary sources for 

energy production as carbon neutral.36 

EPA will continue to evaluate the 

applicability of this policy of treating 

forest-biomass derived biogenic CO2 as 

carbon neutral based on relevant 

information, including data from 

interagency partners on updated trends 

in forest carbon stocks. 

EPA solicits comments on the 

inclusion of forest-derived biomass as a 

compliance option for affected units to 

meet state plan standards under this 

rule (Comment C–20). The Agency also 

solicits comment on the inclusion of 

non-forest biomass (e.g., agricultural, 

waste stream-derived) for energy 

production as a compliance option, and 

what value to attribute to the biogenic 

CO2 emissions associated with nonforest biomass feedstocks (Comment C– 

21). EPA recognizes that CCS 

technology (described above in this 

section) could be applied in conjunction 

with biomass use. 

1. State Discretion To Consider 

Remaining Useful Life and Other 

Factors in Setting Standards of 

Performance 

Section 111(d)(1) requires that EPA’s 

regulations must permit states to take 

into account, among other factors, an 

affected source’s remaining useful life 

when establishing an appropriate 

standard of performance. In other 

words, Congress explicitly envisioned 

under section 111(d)(1) that states could 

implement standards of performance 

that vary from EPA’s emission 

guidelines under appropriate 

circumstances. 

Congress explicitly mentions 

consideration of remaining useful life in 

111(d). Ultimately remaining useful life 

impacts cost. When EPA develops a 

BSER, EPA typically considers factors 

such as cost relative to assumptions 

about a typical unit. If the remaining 

useful life of a particular unit is less, 

that will generally increase the cost of 

control because the time to amortize 

capital costs is less. When congress 

mentions other factors, EPA believes 

that these are generally other factors that 

may substantially increase costs relative 

to a more typical unit. 

As such, EPA is proposing, as part of 

the proposed implementing regulations, 

to permit states to take into account 

remaining useful life, among other 

factors, in establishing a standard of 

performance for a particular affected 

source, consistent with section 

111(d)(1)(B). EPA solicits comments on 

the manner in which states should be 

permitted to exercise their statutory 

authority to take into account remaining 

useful life and on what ‘‘other factors’’ 

might appropriately be besides 

remaining useful life (Comment C–22). 

As described in Section VII.F., EPA 

further proposes as part of the new 

implementing regulations that the 

following factors give meaning to 

section 111(d)(1)(B): 

• Unreasonable cost of control 

resulting from plant age, location, or 

basic process design; 

• Physical impossibility of installing 

necessary control equipment; or 

Other factors specific to the facility 

(or class of facilities) that make 

application of a less stringent standard 

or final compliance time significantly 

more reasonable. Given that there are 

unique attributes and aspects of each 

affected source, there are important 

factors that influence decisions to invest 

in technologies to meet a potential 

performance standard. These include 

timing considerations like expected life 

of the source, payback period for 

investments, the timing of regulatory 

requirements, and other unit-specific 

criteria. The state may find that there 

are space or other physical barriers to 

implementing certain HRIs at specific 

units. Or the state may find that some 

heat rate improvement options are 

either not applicable or have already 

been implemented at certain units. EPA 

understands that many of these ‘‘other 

factors’’ that can affect the application 

of the BSER candidate technologies 

distill down to a consideration of cost. 

Applying a specific candidate 

technology at an affected EGU can be a 

unit-by-unit determination that weighs 

the value of both the cost of installation 

and the CO2 reductions. Accordingly, 

EPA proposes that these factors are the 

types that are specific to the facility (or 

class of facilities) that make a variance 

from the emission guideline 

significantly more reasonable, as 

allowed under proposed 40 CFR 

60.24a(e)(3). EPA, therefore, proposes to 

allow states to take these factors into 

account in establishing a standard of 

performance for state plans in response 

to this emission guideline. EPA further 

solicits comments on what are other 

factors that states should be allowed to 

consider in establishing a standard of 

performance, per the proposed variance 

provision (Comment C–23). 

As previously described, EPA 

proposes that states that utilize the 

proposed variance provision in the new 

implementing regulations to establish a 

less stringent standard of performance 

for an affected EGU and/or a compliance 

schedule that is longer than that 

contemplated in EPA’s final emission 

guideline must demonstrate as part of 

their state plan submission that such 

application of the provision meets the 

criteria described in the factors in 

Section VII.D. EPA also recognizes that 

for some sources, the criteria may result 

in determining that no measures in the 

candidate technologies are applicable. 

Two examples of this might be a unit 

with a very short remaining useful life 

or a unit that has already implemented 

all of the candidate technologies of the 

BSER. In cases such as these, a state 

should still establish a standard of 

performance. In the case of a unit with 

a short remaining useful life, EPA takes 

comment on what such a standard 

might look like (Comment C–24). For 

instance, a state could set a standard 

using both an emission rate and a 

compliance deadline to address this 

instance. The emission standard would 

only be applicable if a source did not 

shut down by the compliance deadline. 

In the case of an affected EGU that has 

already implemented all of the 

candidate technologies, EPA would 

expect that a state set a standard of 

performance that would reflect an 

emission rate that is at least as stringent 

as ‘‘business as usual’’ for that source 

without allowing for any backsliding on 

performance. EPA requests comment on 

these proposed treatments of a source 

that either has a short remaining useful 


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37While CAA section 116 allows for states to 

adopt more stringent state laws, and provides that 

the CAA does not preempt such state laws, it does 

not provide that those more stringent standards are 

federalized. 

life or has already implemented all of 

the HRIs identified as the BSER. 

EPA is also generally soliciting 

comment on whether there are 

considerations in allowing states to 

utilize this proposed variance provision 

in the new implementing regulations in 

response to the final emission guideline, 

including the potential interaction of 

the compliance flexibilities proposed in 

this proposal with utilization of the 

provision (Comment C–25). For 

example, could states authorize trading 

as a compliance mechanism for affected 

EGUs and additionally invoke this 

provision, or would utilizing both 

trading and this provision in 

establishing standards in a state plan 

potentially result in such standards 

going beyond what section 111(d) 

permits (i.e., would allowing for both 

trading and a variance with respect to 

the same standard result in a standard 

that is impermissibly less stringent than 

what application of the BSER in 

conjunction with invocation of this 

provision would result in)? EPA 

welcomes comments on the legality and 

appropriateness of utilizing this 

provision generally, and in the context 

of specific compliance flexibilities that 

states may employ in developing their 

plans (Comment C–26). 

Another consideration for states in 

determining a standard of performance 

with consideration to unique aspects at 

an affected EGU is the interaction 

between BSER and NSR. EPA is aware 

that the prospect of triggering NSR, and 

its associated permitting requirements, 

may have discouraged sources from 

implementing some heat rate 

improvements previously. In Section 

VIII of this preamble, EPA discusses 

proposed changes to alleviate NSR 

burdens for EGUs undertaking heat rate 

improvements. The proposed action on 

NSR would ultimately impact the level 

of reductions reflected in the standard 

of performance that a state establishes 

for its sources. In considering each of 

the candidate technologies, EPA 

believes it is appropriate for states to 

consider the potential that the 

application of HRI may trigger NSR for 

some sources, and associated NSR 

requirements could ultimately impact 

the cost of HRI and the way the state 

applies standards to an affected EGU. 

EPA solicits comment on any factors 

that may play a role in a state setting a 

standard of performance with 

consideration to NSR (Comment C–27). 

2. Averaging and Trading 

EPA solicits comment on the question 

of whether CAA section 111(d) 

authorizes states to include averaging 

and trading between existing sources in 

the plans they submit to meet the 

requirements of a final emission 

guideline (Comment C–28). Section 

111(d)(1) provides that states shall 

submit a plan which (A) establishes 

standards of performance for any 

existing source of certain air pollutants 

to which a 111(b) standard would apply 

if they were new sources, and (B) 

provides for the implementation and 

enforcement of such standards of 

performance. EPA’s regulations under 

section 111(d) must permit the state, in 

applying a standard of performance to 

any particular existing source under a 

state plan, to consider, among other 

factors, the remaining useful life of that 

source. 

To be clear, this section discusses 

averaging in the context of averaging 

across a facility and across multiple 

existing sources. For a discussion on 

EPA allowing individual EGU emissions 

averaging over a period of time, see 

Section VI.C. 

EPA is proposing to allow states to 

incorporate, as a part of their plan, 

emissions averaging among EGUs across 

a single facility. The Agency’s 

determination of the BSER is predicated 

on measures that can be implemented at 

the facility level and averaging across a 

facility is consistent with the proposed 

BSER. EPA is proposing that averaging 

at a facility only be applicable to 

affected EGUs (i.e. coal-fired steam 

EGUs) for several reasons. First, if 

averaging could include non-affected 

EGUs, this might not result in real 

reductions, but simply result in 

averaging with lower-emitting emitting 

fossil-fuel-fired EGUs such as NGCC 

units that would have been operating 

anyway. Further, even if it did result in 

generation shifting to lower emitting 

units it is contrary to the intention of 

the rule which is to focus on reducing 

the rate at coal-fired EGUs when they 

run, not to reduce the amount they run. 

Second, EPA is currently considering 

whether NGCC units should become 

affected EGUs. How NGCC units fit into 

an averaging program will be 

determined if a determination is made 

that they are affected EGUs in this 

program. Third, EPA is proposing that 

facility-wide averaging only apply to 

affected EGUs because it would mirror 

the BSER determination for this rule. 

The EPA solicits comment on whether 

this type of facility-wide averaging of 

affected EGUs is appropriate and 

whether there should be other types of 

considerations involved (Comment C– 

29). EPA is also taking comment on the 

possibility of averaging affected EGUs 

with non-affected EGUs within a facility 

in the limited case when they represent 

incremental new non-emitting capacity 

(Comment C–30). This would be 

consistent with a compliance option 

such as integrated solar. 

Notwithstanding EPA’s discussion 

above, EPA believes that there are both 

legal and practical concerns may weigh 

against the inclusion of averaging and 

trading between existing sources in state 

plans at any level more broad than 

averaging between sources across a 

particular facility. First, EPA is 

concerned that averaging and trading 

across affected sources (or between 

affected sources and non-affected 

sources, e.g., wind turbines) would be 

inconsistent with our proposed 

interpretation of the BSER as limited to 

measures that apply at and to an 

individual source. Because state plans 

must establish standards of 

performance—which by definition 

‘‘reflect . . . the application of the 

[BSER],’’ CAA section 111(a)(1)— 

implementation and enforcement of 

such standards should correspond with 

the approach used to set the standard in 

the first place. Applying a different 

analytical approach to standard-setting 

may result in asymmetrical regulation 

(for example, a state’s implementation 

measures might result in a more 

stringent standard than could otherwise 

be derived from application of the 

BSER).37

Second, EPA believes that if section 

111(d) authorized states to include 

trading and averaging between sources 

in their plans, the express provision 

under 111(d)(1) authorizing states to 

consider existing sources’ remaining 

useful life and other factors when 

establishing and applying standards of 

performance could be viewed as 

superfluous. Once a state takes into 

consideration a source’s remaining 

useful life and other factors (e.g., 

unreasonable cost of control resulting 

from plant age, location, or basic 

process design; physical impossibility of 

installing necessary control equipment; 

whether the source has already 

undertaken some of the measures 

encompassed in the BSER; or other 

factors), then additional compliance 

flexibilities may not be required or 

otherwise appropriate. Indeed, 

averaging and trading by themselves 

would appear to eliminate the need to 

take into consideration a source’s 

remaining useful life: If a source cannot 

meet a performance standard (or if it is 

impractical or inadvisable to require 

that source to do so), but if the state, in 

its plan, is authorized to permit that 


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source to average or otherwise obtain 

credits for its performance with other 

sources’ performance, there may have 

been no need for Congress to 

specifically require EPA to permit states 

to conduct a remaining-useful-life 

analysis. Moreover, the source-focused 

language in 111(d)(1) both generally 

weighs in favor of EPA’s proposed 

interpretation of the BSER as limited to 

source-specific measures, and 

specifically weighs against interpreting 

section 111(d) to authorize state plans to 

include averaging and trading. 

Third, multiple practical concerns 

regarding emissions averaging and 

trading between sources inform EPA’s 

concerns regarding inclusion of those 

mechanisms in state plans under section 

111(d) and its solicitation of comment 

on this issue. These concerns include 

the relative complexity of development 

and implementation of a state plan that 

includes averaging or trading, as well as 

the difficulty in ensuring robust 

compliance with standards of 

performance by means of averaging or 

trading. Trading programs necessitate 

developing adequate means of 

evaluation, monitoring, and verification 

(EM&V) to ensure that standards of 

performance are actually complied with, 

and these programmatic aspects 

increase the burden on states in 

developing a satisfactory state plan, and 

on sources in demonstrating 

compliance. Additionally, either a massbased or rate-based trading program 

potentially brings into question of 

whether the state has established 

standards of performance that 

appropriately reflect the BSER. Under a 

trading program, a single source could 

potentially shut down or reduce 

utilization to such an extent that its 

reduced or eliminated operation 

generates adequate compliance 

instruments for a state’s remaining 

sources to meet their standards of 

performance without implementing any 

additional measures at any other source. 

This compliance strategy might 

undermine EPA’s BSER, which EPA is 

proposing to determine as a menu of 

heat rate improvements. It would also 

undermine the purpose of section 111 in 

a broader sense. The section is directed 

toward the improvement of performance 

of new sources, and, through section 

111(d)’s specific procedures, of existing 

sources. It is not, under EPA’s proposed 

interpretation of section 111 (and 

contrary to the interpretation underlying 

the CPP), directed toward the aggregate 

emissions of an industrial sector as a 

whole, at either the state or national 

level. Adopting an interpretation of 

section 111(d) that could lead to relying 

on the shutdown or reduced operation 

of one or a small handful of sources in 

order to cap or limit the source 

category’s aggregate emissions, while 

not resulting in the improved 

performance of any other source, may be 

contrary to the structure and purpose of 

section 111 as a whole and section 

111(d) specifically. 

However, EPA recognizes that there 

are significant benefits of averaging and 

trading across affected sources and is 

interested in whether emissions 

averaging could be a way to provide 

flexibility while still focusing on a core 

tenet of the BSER for this rule: Reducing 

emissions per MWH of coal-fired 

generation. Since averaging traditionally 

focuses only on the emission rate during 

hours of operation, it focuses on 

encouraging lowering emissions per 

MW generated and not on encouraging 

generation shifting away from the 

affected source category. The EPA 

welcomes comment on whether there is 

a way to allow trading between affected 

EGUs across affected sources while not 

encouraging generation shifting 

(Comment C–31). 

EPA is soliciting comment on whether 

section 111(d) should be read not to 

authorize states to include trading and 

averaging between sources, EPA is also 

interested in affording flexibility to 

states and sources in meeting their 

respective obligations and solicits 

public comment on whether this 

proposed interpretation and conclusion 

is compatible with that goal. EPA is 

primarily interested in comments 

pertaining to whether averaging could 

and should be allowed for trading, and 

to what degree (i.e., averaging across a 

state, or trading) (Comment C–32). If a 

commenter believes that averaging 

across multiple affected sources should 

be allowed as part of a state’s plan, EPA 

requests comment on how the averaging 

system should conceptually work 

(Comment C–33). EPA requests 

comment on how allowing averaging 

across multiple affected sources would 

or would not undermine the BSER 

determination (Comment C–34). If a 

commenter believes that trading should 

be allowed as part of a state’s plan, EPA 

requests comment on what type of 

EM&V criteria should be included for 

the compliance instruments (Comment 

C–35). If a commenter believes that 

trading should be allowed as part of a 

state’s plan, EPA requests comment on 

whether sources should be allowed to 

bank compliance instruments (Comment 

C–36). If a commenter believes that 

averaging across multiple affected 

sources should be allowed as part of a 

state’s plan, EPA requests comment on 

what mechanisms states would need to 

employ to ensure compliance is 

maintained and tracked for purposes of 

providing for the implementation and 

enforcement of the standards of 

performance (Comment C–37). If a 

commenter believes that averaging 

across multiple affected sources should 

be allowed as part of a state’s plan, EPA 

requests comment on which and/or if 

technology should be limited in the 

averaging program (Comment C–38). If a 

commenter believes that averaging 

across multiple affected sources should 

be allowed as part of a state’s plan, EPA 

requests comment on whether affected 

EGUs across state lines could be able to 

average and what measures state plans 

should include to provide for the 

implementation and enforcement of 

such multi-state averaging (Comment C– 

39). EPA further requests comment on 

the issues of statutory interpretation laid 

forth above, whether they are 

appropriate interpretations of section 

111(d) specifically and section 111 

generally, in terms of the provision’s 

text, structure, and purpose (Comment 

C–40). EPA additionally solicits 

comment on whether such averaging, 

trading, or ‘‘bubbling’’ compliance 

flexibilities as are available under other 

sections of title I of the CAA suggest that 

such flexibilities should be afforded 

under state plans under section 111(d) 

(Comment C–41). 

C. Submission of State Plans 

Section 111(d)(1) of the Clean Air Act 

requires that in addition to establishing 

standards of performance for affected 

sources, such plans must also provide 

for the implementation and enforcement 

of such standards. As described in 

Section VII, EPA is proposing new 

implementing regulations for section 

111(d), which in part carry over a 

number of the same provisions currently 

present in the existing implementing 

regulations under 40 CFR part 60, 

subpart B. EPA is proposing that these 

provisions apply for states to meet the 

requirement that state plans include 

implementation and enforcement 

measures. EPA requests comment on 

whether these provisions are 

appropriate to apply for purposes of 

meeting obligations under a final rule in 

response to this proposal, or whether 

other implementation or enforcement 

measures should be required (Comment 

C–42). 

Additionally, EPA is proposing that 

states must include appropriate 

monitoring, reporting, and 

recordkeeping requirements to ensure 

that state plans adequately provide for 

the implementation and enforcement of 

standards of performance. Each state 

will have the flexibility to design a 


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38The authority to reconsider prior decisions 

exists in part because EPA’s interpretations of 

statutes it administers ‘‘[are not] instantly carved in 

stone,’’ but must be evaluated ‘‘on a continuing 

basis.’’ Chevron U.S.A. Inc. v. NRDC, Inc., 467 U.S. 

837, 863–64 (1984). Indeed, ‘‘[a]gencies obviously 

have broad discretion to reconsider a regulation at 

any time.’’ Clean Air Council v. Pruitt, 862 F.3d 1, 

8–9 (DC Cir. 2017). 

monitoring program for assessing 

compliance with the standards of 

performance identified in the plan. Most 

potentially affected coal-fired EGUs 

already continuously monitor CO2

emissions, heat input, and gross electric 

output and report hourly data to EPA 

under 40 CFR part 75. Accordingly, if a 

state plan establishes a standard of 

performance for a unit’s CO2 emissions 

rate (e.g., lb/MWh), EPA proposes that 

states may elect to use data collected by 

EPA under 40 CFR part 75 to meet the 

required monitoring, reporting, and 

recordkeeping requirements under this 

emission guideline. 

EPA also notes that states have it 

within their discretion to establish 

averaging times for affected EGUs. 

Averaging the emission rate of an 

affected EGU over different time periods 

may have different effects on the 

demonstration of compliance for an 

EGU to the state. EPA solicits comment 

on whether there should be any bounds 

or consideration to the averaging times 

that states are allowed to consider 

(Comment C–43). 

EPA is further proposing to apply 

generally the proposed new 

implementing regulations for timing, 

process and required components for 

state plan submissions and 

implementation for state plans required 

under for affected EGUs. The new 

implementing regulations are described 

in detail in Section VII. In addition to 

application of the implementing 

regulations to state plans in response to 

a final emission guideline under this 

proposal, EPA is also proposing that 

state plans be comprehensively 

submitted electronically through an 

EPA provided platform. EPA solicits 

comment on whether electronic 

submittals are appropriate and less 

burdensome to states (Comment C–44) 

and whether this should be the sole 

means of submitting state plans 

(Comment C–45). EPA believes that 

electronic submittals will ease the 

burden of state plan submittals for both 

states and EPA. 

In section 60.5740a of the regulatory 

text for this proposal, there is 

description and list of what a state plan 

must include. EPA solicits comment on 

whether this list is comprehensive to 

submit a state plan (Comment C–46). 

VII. Proposed New Implementing 

Regulations for Section 111(d) Emission 

Guidelines 

Distinct from EPA’s proposed 

emission guidelines for the regulation of 

GHGs for existing affected EGUs, EPA is 

also proposing to promulgate new 

regulations to implement section 111(d) 

regulations. As previously described, 

the current implementing regulations at 

40 CFR part 60, subpart B were 

promulgated in 1975 [See 40 FR 53346.]. 

Section 111(d)(1) of the CAA explicitly 

requires that EPA establish regulations 

similar to those under section 110 of the 

CAA to establish a procedure for states 

to submit plans to EPA. The 

implementing regulations have not been 

significantly revised since their original 

promulgation in 1975. Notably, the 

implementing regulations do not reflect 

section 111(d) in its current form as 

amended by Congress in 1977, and do 

not reflect section 110 in its current 

form as amended by Congress in 1990. 

Accordingly, EPA believes that certain 

portions of the implementing 

regulations do not appropriately align 

with section 111(d), contrary to that 

provision’s mandate that EPA’s 

regulations be ‘‘similar’’ to the 

provisions under section 110. Therefore, 

EPA is proposing to promulgate new 

implementing regulations that are in 

accordance with the statute in its 

current form. As previously discussed, 

agencies have the ability to revisit prior 

decisions, and EPA believes it is 

appropriate to do so here in light of the 

potential mismatch between certain 

provisions of the implementing 

regulations and the statute.38

EPA is proposing to largely carry over 

the current implementing regulations in 

40 CFR part 60, subpart B to a new 

subpart that will be applicable to EPA’s 

emission guidelines and state plans or 

federal plans associated with such 

emission guidelines, both those 

contemplated in this proposal and for 

any others that may be published or 

promulgated either concurrently or 

subsequent to final promulgation of the 

new implementing regulations. For 

purposes of regulatory certainty, EPA 

believes it is appropriate to apply these 

new implementing regulations 

prospectively, and retain the existing 

implementing regulations as applicable 

to section 111(d) emission guidelines 

and associated state plans that were 

promulgated previously. Additionally, 

the existing implementing regulations at 

40 CFR part 60, subpart B are applicable 

to regulations promulgated under CAA 

section 129, and associated state plans. 

EPA intends to retain the applicability 

of the existing implementing regulations 

with respect to rules and state plans 

associated with section 129, and the 

proposed new implementing regulations 

are intended to apply only to section 

111(d) regulations and associated state 

plans issued solely under the authority 

of section 111(d). EPA requests 

comments on this proposed 

applicability of both the existing and 

new implementing regulations 

(Comment C–47). 

EPA is aware that there are a number 

of cases where state plan submittal and 

review processes are still ongoing for 

existing 111(d) emission guidelines. 

Because EPA is proposing changes to 

the timing requirements to more closely 

align 111(d) with both general SIP 

submittal timing requirements and 

because of the realities of how long 

these actions take, EPA is proposing to 

apply the changes to timing 

requirements to both emission 

guidelines published after the new 

implementing regulations are finalized, 

and to all ongoing emission guidelines 

already published under section 111(d). 

EPA is soliciting comment on the 

proposed timing requirements for 

prospective emission guidelines under 

the new implementing regulations and 

the alignment of ongoing emission 

guidelines by amending their respective 

regulatory text to incorporate the new 

timing requirements. (Comment C–48). 

EPA is proposing to apply the timing 

changes to all ongoing 111(d) 

regulations for the same reasons that 

EPA is changing the timing 

requirements prospectively. Based on 

years of experience with working with 

states to develop SIPs under section 

110, EPA believes that given the 

comparable amount of work, effort, 

coordination with sources, and the time 

required to develop state plans that 

more time is necessary for the process. 

Giving states three years to develop state 

plans is more appropriate than the nine 

months provided for under the existing 

implementing regulations considering 

the workload. These practical 

considerations regarding the time 

needed for state plan development are 

also applicable and true for recent 

emission guidelines where the state 

plan submittal and review process are 

still ongoing. 

For those provisions that are being 

carried over from the existing 

implementing regulations into the new 

implementing regulations, EPA believes 

the placement of those provisions under 

a new subpart is a ministerial action 

that does not require reopening the 

substance of those provisions for notice 

and comment. EPA is not intending to 

substantively change those provisions 

from their original promulgation, and 

continues to rely on the record under 


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which they were promulgated. 

Therefore, EPA is not soliciting 

comment on the following provisions, 

which remain substantively the same 

from their original promulgation: 40 

CFR 60.21a(a)–(d), (g)–(j) (Definitions); 

60.22a(a), 60.22a(b)(1)–(3), (b)(5), (c) 

(Publication of emission guidelines); 

60.23a(a)–(c), (d)(3)–(5), (e)–(h) 

(Adoption and submittal of State plans; 

public hearings); 60.24a(a)–(d), (f) 

(Standards of performance and 

compliance schedules); 60.25a 

(Emission inventories, source 

surveillance, reports); 60.26a (Legal 

authority); 60.27a(a), (e)–(f) (Actions by 

the Administrator); 60.28a(b) (Plan 

revisions by the State); 60.29a (Plan 

revisions by the Administrator). 

EPA is also sensitive to potential 

confusion over whether these new 

implementing regulations would apply 

to an emission guideline previously 

promulgated or to state plans associated 

with a prior emission guideline, so EPA 

is proposing that the new implementing 

regulations are applicable only to 

emission guidelines and associated 

plans developed after promulgation of 

this regulation, including the emission 

guideline being proposed as part of this 

action for GHGs and existing affected 

EGUs. EPA solicits comment on this 

proposed applicability of the new 

implementing regulations (Comment C– 

49). 

While EPA is carrying over a number 

of requirements from the existing 

implementing regulations, EPA is 

proposing specific changes to better 

align the regulations with the statute. 

These changes are reflected in the 

proposed regulatory text for this action, 

and EPA solicits comments on both the 

substance of these changes and the 

proposed regulatory text (Comment C– 

50). These changes include: 

• An explicit provision allowing a 

specific emission guideline to supersede 

the requirements of the new 

implementing regulations; 

• Changes to the definition of 

‘‘emission guideline’’; 

• Updated timing requirements for 

the submission of state plans; 

• Updated timing requirements for 

EPA’s action on state plans; 

• Updated timing requirements for 

EPA’s promulgation of a federal plan; 

• Updated timing requirement for 

when increments of progress must be 

included as part of a state plan; 

• Completeness criteria and a process 

for determining completeness of state 

plan submissions similar to CAA 

section 110(k)(1) and (2); 

• Updated definition replacing 

‘‘emission standard’’ with ‘‘standard of 

performance;’’ 

• Usage of the internet to satisfy 

certain public hearing requirements; 

• No longer making a distinction 

between public health-based and 

welfare-based pollutants in an emission 

guideline; and, 

• Updating the variance provision to 

be consistent with CAA section 

111(d)(1)(B). 

EPA is proposing to include a 

provision in the new implementing 

regulations that expressly allows for any 

emission guideline to supersede the 

applicability of the implementing 

regulations as appropriate. EPA cannot 

foresee all of the unique circumstances 

and factors associated with a particular 

future emission guideline, and therefore 

different requirements may be necessary 

for a particular 111(d) rulemaking that 

EPA cannot envision at this time. The 

proposed provision is parallel to one 

contained in the 40 CFR part 63 General 

Provisions implementing section 112 of 

the CAA. EPA solicits comments on the 

inclusion of such provision as part of 

the implementing regulations for section 

111(d) (Comment C–51). 

Because EPA is updating the 

implementing regulations and many of 

the provisions from the existing 

implementing regulations are being 

carried over, EPA wants to be clear and 

transparent with regard to the changes 

that are being made to the implementing 

regulations. As such, EPA is providing 

Table 4 that summarizes the changes 

being made. EPA also has included in 

the docket for this action a red-linestrike-out of the changes that are being 

proposed. 

TABLE 4—SUMMARY OF CHANGES TO THE IMPLEMENTING REGULATIONS

New implementing regulations—subpart Ba for all future 111(d) 

emission guidelines 

Existing implementing regulations—subpart B for all previously 

promulgated 111(d) emission guidelines 

Explicit authority for a new 111(d) emission guideline requirement to 

supersede these implementing regulations.

No explicit authority. 

Use of term ‘‘guideline document’’; does not require EPA to provide a 

presumptive emission standard.

Use of term ‘‘emission guideline’’; arguably required EPA to provide a 

presumptive emission standard. 

Use of term ‘‘standard of performance’’ ................................................... Use of term ‘‘emission standard’’. 

‘‘Standard of performance’’ allows states to include design, equipment, 

work practice, or operational standards when EPA determines it’s not 

feasible to prescribe or enforce a standard pf performance, consistent with the requirements of CAA section 111(h).

‘‘Emission standard’’ allows states to prescribe equipment specifications when EPA determines it’s clearly impracticable to establish an 

emission standard. 

State submission timing: 3 years from promulgation of a final emission 

guideline.

State submission timing: 9 months from promulgation of a final emission guideline. 

EPA action on state plan submission timing: 12 months after determination of completeness.EPA action on state plan submission timing: 4 months after submittal 

deadline. 

Timing for EPA promulgation of a federal plan, as appropriate: 2 years 

after finding of failure to submit a complete plan, or disapproval of 

state plan.

Timing for EPA promulgation of a federal plan, as appropriate: 6 

months after submittal deadline. 

Increments of progress are required if compliance schedule for a state 

plan is longer than 24 months after the plan is due.

Increments of progress are required if compliance schedule for a state 

plan is longer than 12 months after the plan is due. 

Completeness criteria and process for state plan submittals .................. No previous discussion. 

Usage of the internet to satisfy certain public hearing requirements ...... No previous discussion. 

No distinction made in treatment between health-based and welfarebased pollutants; variance provision available regardless of type of 

pollutant.

Different provisions for health-based and welfare-based pollutants; 

state plans must be as stringent as EPA’s emission guideline for 

health-based pollutants unless variance provision is invoked. 


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A. Changes to the Definition of 

‘‘Emission Guideline’’ 

The existing implementation 

regulations under 40 CFR 60.21(e) 

contain a definition of ‘‘emission 

guideline’’, defining it as a guideline 

which reflects the degree of emission 

reduction achievable through the 

application of the best system of 

emission reduction which (taking into 

account the cost of such reduction) the 

Administrator has determined has been 

adequately demonstrated for designated 

facilities. This definition additionally 

references that an emission guideline 

may be set forth in 40 CFR part 60, 

subpart C or a ‘‘final guideline 

document’’ published under 40 CFR 

60.22(a). While the implementing 

regulations do not define the term ‘‘final 

guideline document,’’ 40 CFR 60.22 

generally contains a number of 

requirements pertaining to the contents 

of guideline documents, which are 

intended to provide information for the 

development of state plans. See 40 CFR 

60.22(b). The preambles for both the 

proposed and final existing 

implementing regulations suggest that 

an ‘‘emission guideline’’ would be a 

guideline provided by EPA that 

presumptively reflects the degree of 

emission limitation achievable by the 

BSER. EPA believes it is important to at 

least provide information on such 

degree of emission limitation in order to 

guide states in their establishment of 

standards of performance as required 

under CAA section 111(d). However, 

EPA does not believe anything in CAA 

section 111(a)(1) or section 111(d) 

compels EPA to provide a presumptive 

emission standard that reflects the 

degree of emission limitation achievable 

by application of the BSER. 

Accordingly, as part of the new 

implementing regulations, EPA 

proposes to re-define ‘‘emission 

guideline’’ as a final guideline 

document published under § 60.22a(a), 

which includes information on the 

degree of emission reduction achievable 

through the application of the best 

system of emission reduction which 

(taking into account the cost of such 

reduction and any nonair quality health 

and environmental impact and energy 

requirements) EPA has determined has 

been adequately demonstrated for 

designated facilities. 

B. Updates to Timing Requirements 

The timing requirements in the 

existing implementing regulations for 

state plan submissions, EPA’s action on 

state plan submissions and EPA’s 

promulgation of federal plans generally 

track the timing requirements for SIPs 

and federal implementation plans (FIPs) 

under the 1970 version of the Clean Air 

Act. Congress revised these SIP/FIP 

timing requirements in section 110 as 

part of the 1990 Clean Air Act 

amendments. EPA proposes to 

accordingly update the timing 

requirements regarding state and federal 

plans under section 111(d) to be 

consistent with the current timing 

requirements for SIPs and FIPs under 

section 110. The existing implementing 

regulations at 40 CFR 60.23(a)(1) 

requires state plans to be submitted to 

EPA within nine months after 

publication of a final emission 

guideline, unless otherwise specified in 

an emission guideline. EPA is 

proposing, as part of new implementing 

regulations, to provide states with three 

years after the notice of the availability 

of the final emission guideline to adopt 

and submit a state plan to EPA. Because 

of the amount of work, effort, and time 

required for developing state plans that 

include unit-specific standards, and 

implementation and enforcement 

measures for such standards, EPA 

believes that extending the submission 

date of state plans from nine months to 

three years is appropriate. Because 

states have considerable flexibility in 

implementing section 111(d), this 

timing also allows states to interact and 

work with the Agency in the 

development of state plan and minimize 

the chances of unexpected issues arising 

that could slow down eventual approval 

of state plans. EPA solicits comment on 

generally providing states with three 

years after the publication of the final 

emission guidelines, and solicits 

comment on any other timeframes that 

may be appropriate for submission of 

state plans given the flexibilities EPA 

intends to provide through its emission 

guidelines (Comment C–52). EPA also 

proposes to give itself discretion to 

determine in a specific emission 

guideline that a shorter time period for 

the submission of state plans particular 

to that emission guideline is 

appropriate. Such authority is 

consistent with CAA section 110(a)(1)’s 

grant of authority to the Administrator 

to determine that a period shorter than 

three years is appropriate for the 

submission of particular SIPs 

implementing the NAAQS. 

Following submission of state plans, 

EPA will review plan submittals to 

determine whether they are 

‘‘satisfactory’’ as per CAA section 

111(d)(2)(A). Given the flexibilities 

section 111(d) and emission guidelines 

generally accord to states, and EPA’s 

prior experience on reviewing and 

acting on SIPs under section 110, EPA 

is proposing to extend the period for 

EPA review and approval or disapproval 

of plans from the four-month period 

provided in EPA implementing 

regulations to a twelve-month period 

after a determination of completeness 

(either affirmatively by EPA or by 

operation of law, see below for EPA’s 

proposal on completeness) as part of the 

new implanting regulations. This 

timeline will provide adequate time for 

EPA to review plans and follow noticeand-comment rulemaking procedures to 

ensure an opportunity for public 

comment on EPA’s proposed action on 

a state plan. EPA solicits comment on 

extending the timing of EPA’s action on 

a state plan from 4 months of when a 

plan is due to 12 months from 

determination that a state plan 

submission is complete (Comment C– 

53). 

EPA additionally proposes to extend 

the timing from six months in the 

existing implementing regulations to 

two years, as part of new implementing 

regulations, for EPA to promulgate a 

federal plan for states that fail to submit 

an approvable state plan in response to 

a final emission guideline. This twoyear timeline is consistent with the FIP 

deadline under section 110(c) of the 

CAA. EPA solicits comment on change 

in timing for EPA to promulgate a 

federal plan from six months to two 

years (Comment C–54). EPA solicits 

comment on extending deadline for 

promulgating a final (i.e., after 

appropriate notice and comment) 

federal plan for a state to two years after 

either (1) EPA finds that a state has 

failed to submit a complete plan, or (2) 

EPA disapproves a state plan 

submission (Comment C–55). 

C. Compliance Deadlines 

The existing implementing 

regulations require that any compliance 

schedule for state plans extending more 

than 12 months from the date required 

for submittal of the plan must include 

legally enforceable increments of 

progress to achieve compliance for each 

designated facility or category of 

facilities. 40 CFR 60.24(e)(1). However, 

as described in section VII.B, the EPA is 

proposing certain updates to the timing 

requirements for the submission of, and 

action on, state plans. Consequently, it 

follows that the requirement for 

increments of progress should also be 

updated in order to align with the 

proposed new timelines. Given that the 

EPA is proposing a period of up to 18 

months for its action on state plans (i.e. 

12 months from the determination that 

a state plan submission is complete, 

which could occur up to six months 

after receipt of the state plan), EPA 


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believes it is appropriate that the 

requirement for increments of progress 

should attach to plans that contain 

compliance periods that are longer than 

the period provided for EPA’s review of 

such plans. This way, sources subject to 

a plan have more certainty that their 

regulatory compliance obligations 

would not change between the period 

between when a state plan is due and 

when EPA acts on a plan. Accordingly, 

EPA proposes that increments of 

progress will be included for state plans 

that contain compliance schedules 

longer than 24 months from the date 

when state plans are due for a particular 

emission guideline. EPA solicits 

comments on whether this 24-month 

component, or some other period of 

time, is appropriate as a trigger for 

requiring increments of progress as part 

of a plan’s compliance schedule. 

D. Completeness Criteria 

Similar to requirements regarding 

determinations of completeness under 

section 110(k)(1), EPA is proposing 

completeness criteria that provide the 

Agency with a means to determine 

whether a state plan submission 

includes the minimum elements 

necessary for EPA to act on the 

submission. EPA would determine 

completeness simply by comparing the 

state’s submission against these 

completeness criteria. In the case of SIPs 

under CAA section 110(k)(1), EPA 

promulgated completeness criteria in 

1990 at Appendix V to 40 CFR part 51 

(55 FR 5830; February 16, 1990). EPA 

proposes to adopt criteria similar to the 

criteria set out at section 2.0 of 

Appendix V for determining the 

completeness of submissions under 

CAA section 111(d). 

EPA notes that the addition of 

completeness criteria in the framework 

regulations does not alter any of the 

submission requirements states already 

have under any applicable emission 

guideline. The completeness criteria 

proposed by this action are those that 

would generally apply to all plan 

submissions under section 111(d), but 

specific emission guidelines may 

supplement these general criteria with 

additional requirements. 

The completeness criteria that EPA is 

proposing in this action can be grouped 

into administrative materials and 

technical support. For administrative 

materials, the completeness criteria 

mirror criteria for SIP submissions 

because the two programs have similar 

administrative processes. Under these 

criteria, the submittal must include the 

following: 

(1) A formal letter of submittal from 

the Governor or the Governor’s designee 

requesting EPA approval of the plan or 

revision thereof. 

(2) Evidence that the state has 

adopted the plan in the state code or 

body of regulations. That evidence must 

include the date of adoption or final 

issuance as well as the effective date of 

the plan, if different from the adoption/ 

issuance date. 

(3) Evidence that the state has the 

necessary legal authority under state 

law to adopt and implement the plan. 

(4) A copy of the official state 

regulation(s) or document(s) submitted 

for approval and incorporated by 

reference into the plan, signed, stamped 

and dated by the appropriate state 

official indicating that they are fully 

adopted and enforceable by the state. 

The effective date of the regulation or 

document must, whenever possible, be 

indicated in the document itself. The 

state’s electronic copy must be an exact 

duplicate of the hard copy. For revisions 

to the approved plan, the submission 

must indicate the changes made to the 

approved plan by redline/strikethrough. 

(5) Evidence that the state followed all 

of the procedural requirements of the 

state’s laws and constitution in 

conducting and completing the 

adoption/issuance of the plan. 

(6) Evidence that public notice was 

given of the plan or plan revisions with 

procedures consistent with the 

requirements of 40 CFR 60.23, including 

the date of publication of such notice. 

(7) Certification that public hearing(s) 

were held in accordance with the 

information provided in the public 

notice and the state’s laws and 

constitution, if applicable and 

consistent with the public hearing 

requirements in 40 CFR 60.23. 

(8) Compilation of public comments 

and the state’s response thereto. 

The technical support required for all 

plans must include each of the 

following: 

(1) Description of the plan approach 

and geographic scope. 

(2) Identification of each designated 

facility; identification of emission 

standards for each designated facility; 

and monitoring, recordkeeping, and 

reporting requirements that will 

determine compliance by each 

designated facility. 

(3) Identification of compliance 

schedules and/or increments of 

progress. 

(4) Demonstration that the state plan 

submission is projected to achieve 

emissions performance under the 

applicable emission guidelines. 

(5) Documentation of state 

recordkeeping and reporting 

requirements to determine the 

performance of the plan as a whole. 

(6) Demonstration that each emission 

standard is quantifiable, nonduplicative, permanent, verifiable, and 

enforceable. 

EPA intends that these criteria be 

generally applicable to all CAA section 

111(d) plans submitted on or after final 

new implementing regulations are 

promulgated, with the proviso that 

specific emission guidelines may 

provide otherwise. 

Consistent with the requirements of 

CAA section 110(k)(1)(B) for SIPs, EPA 

is proposing to determine whether a 

state plan is complete (i.e., meets the 

completeness criteria) no later than 6 

months after the date, if any, by which 

a state is required to submit the plan. 

EPA further proposes that any plan or 

plan revision that a State submits to 

EPA, and that has not been determined 

by EPA by the date 6 months after 

receipt of the submission to have failed 

to meet the minimum completeness 

criteria, shall on that date be deemed by 

operation of law to be a complete state 

plan. Then, as previously discussed, 

EPA is relatedly proposing to act on a 

state plan submission within 12 months 

after determining a plan is complete, 

either through an affirmative 

determination or by operation of law. 

When plan submissions do not 

contain the minimum elements, EPA is 

proposing to find that a state has failed 

to submit a complete plan through the 

same process as finding a state has made 

no submission at all. Specifically, EPA 

would notify the state that its 

submission is incomplete and therefore, 

that it has not submitted a required 

plan, and EPA would also publish a 

finding of failure to submit in the 

Federal Register, which triggers EPA’s 

obligation to promulgate a federal plan 

for the state. This determination that a 

submission is incomplete and the state 

has failed to submit a plan is ministerial 

in nature and requires no exercise of 

discretion or judgment on the Agency’s 

part, nor does it reflect a judgment on 

the eventual approvability of the 

submitted portions of the plan. 

E. Standard of Performance 

As previously described, the 

implementing regulations were 

promulgated in 1975 and effectuated the 

1970 version of the Clean Air Act as at 

it existed at that time. The 1970 version 

of section 111(d) required state plans to 

include ‘‘emission standards’’ for 

existing sources, and consequently the 

implementing regulations refer to this 

term. However, as part of the 1977 

amendments to the CAA, Congress 

replaced the term ‘‘emission standard’’ 

in section 111(d) with ‘‘standard of 

performance.’’ EPA has not since 


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revised the implementing regulations to 

reflect this change in terminology. For 

clarity’s sake and to better track with 

statutory requirements, EPA is 

proposing to include a definition of 

‘‘standards of performance’’ as part of 

the new implementing regulations, and 

to consistently refer to this term as 

appropriate within those regulations in 

lieu of referring to an ‘‘emission 

standard.’’ Additionally, the current 

definition of ‘‘emission standard’’ in the 

implementing regulations is incomplete 

and requires clean-up regardless. For 

example, the definition encompasses 

equipment standards, which is an 

alternative form of standard provided 

for in CAA section 111(h) under certain 

circumstances. However, section 111(h) 

provides for other forms of alternative 

standards, such as work practice 

standards, which are not covered by the 

existing regulatory definition of 

‘‘emission standard.’’ Furthermore, the 

definition of ‘‘emission standard’’ 

encompasses allowance systems, a 

reference that was added as part of 

EPA’s Clean Air Mercury Rule. 70 FR 

28605. This rule was vacated by the D.C. 

Circuit, and therefore this added 

component to the definition of 

‘‘emission standard’’ had no legal effect 

because of the court’s vacatur. 

Consistent with the court’s opinion, 

EPA signaled its intent to remove this 

reference as part of its Mercury Air 

Toxics rule. 77 FR 9304. However, in 

the final regulatory text of that 

rulemaking, EPA did not take action 

removing this reference, and it remains 

as a vestigial artifact. 

For these reasons, EPA is proposing to 

replace the existing definition of 

‘‘emission standard’’ with a definition of 

‘‘standard of performance’’ that tracks 

with the definition provided for under 

CAA section 111(a)(1). This means a 

standard of performance for existing 

sources would be defined as a standard 

for emissions or air pollutants which 

reflects the degree of emission 

limitation achievable through the 

application by the state of the best 

system of emission reduction which 

(taking into account the cost of 

achieving such reduction and any 

nonair quality health and environmental 

impact and energy requirements) the 

Administrator determines has been 

adequately demonstrated. EPA is further 

proposing to incorporate into a 

definition of standard of performance 

CAA section 111(h)’s allowance for 

design, equipment, work practice, or 

operational standards as alternative 

standards of performance under the 

statutorily prescribed circumstances. 

Currently, the existing implanting 

regulations allow for state plans to 

prescribe equipment specifications 

when emission rates are ‘‘clearly 

impracticable’’ as determined by EPA. 

CAA section 111(h)(1) by contrast 

allows for alternative standards such as 

equipment standards to be promulgated 

when standards of performance are ‘‘not 

feasible to prescribe or enforce,’’ as 

those terms are defined under CAA 

section 111(h)(2). Given the potential 

discrepancy between the conditions 

under which alternative standards may 

be established based on the different 

terminology used by the statute and 

existing implementing regulations, EPA 

proposes to use the ‘‘not feasible to 

prescribe or enforce’’ language as the 

condition for the new implementing 

regulations under which alternative 

standards may be established. 

EPA solicits comment on all of these 

means of tracking and incorporating the 

section 111(a)(1) and 111(h) for 

purposes of a regulatory definition of 

‘‘standard of performance,’’ and requests 

comment on any other considerations 

for such definition (Comment C–56). 

F. Variance 

EPA believes that the existing 

implementing regulations’ distinction 

between public health-based and 

welfare-based pollutants is not a 

distinction unambiguously required 

under section 111(d) or any other 

applicable provision of the statute. EPA 

does not believe the nature of the 

pollutant in terms of its impacts on 

health and/or welfare impact the 

manner in which it is regulated under 

this provision. Particularly, 60.24(c) 

requires that for health-based pollutants, 

a state’s standards of performance must 

be of equivalent stringency to EPA’s 

emission guidelines. However, section 

111(d)(1)(B) requires that EPA’s 

regulations must permit states to take 

into account, among other factors, an 

affected source’s remaining useful life 

when establishing an appropriate 

standard of performance. In other 

words, Congress explicitly envisioned 

under section 111(d)(1)(B) that states 

could implement standards of 

performance that vary from EPA’s 

emission guidelines under appropriate 

circumstances. Notably, the 

implementing regulations at 40 CFR 

60.24(f) contain a variance provision 

that allow for states to also apply less 

stringent standards on sources under 

certain circumstances. However, the 

variance provision attaches to the 

distinction between health-based and 

welfare-based pollutants, and is 

available to the states only under EPA’s 

discretion. The variance provision was 

also promulgated prior to Congress’s 

addition of the requirement in section 

111(d)(1)(B) that EPA permit states to 

take into account remaining useful life 

and other factors, and the terms of the 

regulatory provision and statutory 

provision do not match one another, 

meaning that the variance provision 

may not account for all of the factors 

envisioned under section 111(d)(1)(B). 

Given all of these factors, EPA is 

proposing to not make a distinction 

between health-based and welfare-based 

pollutants and attach requirements 

contingent upon this distinction as part 

of the new implementing regulations. 

EPA is also proposing a new variance 

provision to permit states to take into 

account remaining useful life, among 

other factors, in establishing a standard 

of performance for a particular affected 

source, consistent with section 

111(d)(1)(B). 

Given that there are unique attributes 

and aspects of each affected source, 

these other factors may be ones that 

influence decisions to invest in 

technologies to meet a potential 

performance standard. Such other 

factors may include timing 

considerations like expected life of the 

source, payback period for investments, 

the timing of regulatory requirements, 

and other unit-specific criteria. EPA 

solicits comments on how a new 

variance provision can permit states to 

take into account remaining useful life 

and other factors, and what other factors 

might appropriately be (Comment C– 

57). EPA is also soliciting comment on 

whether the factors outlined in the 

existing variance provision at 40 CFR 

60.24(f) are appropriate to carry over to 

a new variance provision if they 

adequately give meaning to the 

requirements of section 111(d)(1)(B) 

(Comment C–58). Those factors are: 

• Unreasonable cost of control 

resulting from plant age, location, or 

basic process design; 

• Physical impossibility of installing 

necessary control equipment; or 

• Other factors specific to the facility 

(or class of facilities) that make 

application of a less stringent standard 

or final compliance time significantly 

more reasonable. 

VIII. New Source Review Permitting of 

HRIs 

A. What is New Source Review? 

The NSR program is a preconstruction 

permitting program that requires 

stationary sources of air pollution to 

obtain permits prior to beginning 

construction. The NSR program applies 

both to new construction and to 

modifications of existing sources. New 

construction and modifications of 


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39 40 CFR 51.165(a)(1)(xxxvii), 40 CFR 

52.21(b)(50). 

40The one exception to this approach is for GHG. 

Regardless of the GHG emissions resulting from 

construction of a new source or modification, the 

source will not be required to obtain a major NSR 

permit unless the emissions of another regulated 

NSR pollutant equal or exceed the major NSR 

threshold. 80 FR 50199 (August 19, 2015); Utility 

Air Regulatory Group v. EPA, 134 S. Ct. 2427 

(2015). 

41PSD applies on a regulated NSR pollutant-byregulated NSR pollutant basis. The PSD 

requirements do not apply to regulated NSR 

pollutants for which the area is designated as 

nonattainment. NNSR could only be applicable 

with regard to a source’s emissions of criteria 

pollutants, as those are the only pollutants with 

respect to which areas are designated as attainment 

or nonattainment. 

42The term ‘best available control technology’ 

means an emission limitation . . . which the 

permitting authority, on a case by case basis, taking 

into account energy, environmental, and economic 

impacts and other costs, determines is achievable 

for such facility . . .’’ 42 U.S.C. 7479(3); see e.g., 

supra Section III.C; PSD and Title V Permitting 

Guidance for Greenhouse Gases (Mar. 2011), 

available at https://www.epa.gov/sites/production/ 

files/2015-07/documents/ghgguid.pdf. 

43The NSR major source and major modification 

emission thresholds are expressed in short tons (i.e., 

2000 lbs.). 

44The NSR regulations expressly exempt certain 

activities from being considered a physical change 

or change in method of operation, including routine 

maintenance, repair and replacement, increases in 

hours of operation or production rate, and change 

in ownership. See, e.g., 40 CFR 52.21(b)(2)(iii). 

45While we are discussing federal regulations, a 

state or local permitting authority may have 

different regulations to define NSR applicability if 

approved by EPA into its implementation plan. 

46EPA’s regulations at 40 CFR 51.160–51.169 

apply to state permitting programs; however, these 

provisions cover both major and minor sources. The 

requirements that apply to strictly minor sources 

are limited to sections 51.160–51.164. In addition, 

in 2011 EPA created the Indian country minor NSR 

permitting program, which authorizes EPA regional 

offices to issue minor source permits on tribal 

lands. These regulations are located at 40 CFR 

49.101–49.104 and 49.151–49.164. 

stationary sources that emit or increase 

emissions of ‘‘regulated NSR 

pollutants’’ 39 at or above certain 

thresholds defined in either the CAA or 

the NSR regulations are subject to major 

NSR requirements, while smaller 

emitting sources and modifications may 

be subject to minor NSR requirements.40

A pollutant is a ‘‘regulated NSR 

pollutant’’ if it meets at least one of four 

requirements, which are, in general, any 

pollutant for which EPA has 

promulgated a NAAQS or a NSPS, 

certain ozone depleting substances, and 

‘‘[a]ny pollutant that otherwise is 

subject to regulation under the Act.’’ 

See, e.g., 40 CFR 52.21(b)(50). For 

purposes of NSR, hazardous air 

pollutants are excluded. Id. 

NSR permits for major sources 

emitting pollutants for which the area is 

classified as attainment or 

unclassifiable, and for other pollutants 

regulated under the CAA, are referred to 

as prevention of significant 

deterioration (PSD) permits. NSR 

permits for major sources emitting 

pollutants for which the area is in 

nonattainment are referred to as 

nonattainment NSR (NNSR) permits. 

The pollutant(s) at issue and the air 

quality designation of the area where 

the facility is located or proposed to be 

built determine the specific permitting 

requirements.41 Among other 

requirements, the CAA requires sources 

subject to PSD to meet emission limits 

based on Best Available Control 

Technology (BACT) as specified by 

section 165(a)(4), and the CAA requires 

sources subject to NNSR to meet the 

Lowest Achievable Emissions Rate 

(LAER) pursuant to section 173(a)(2). 

These technology requirements for 

major NSR permits are not 

predetermined by a rule or state plan, 

but are case-by-case determinations 

made by the permitting authority.42

Other requirements to obtain a major 

NSR permit vary depending on whether 

the source needs a PSD or an NNSR 

permit. 

The test to determine whether a 

source is subject to major NSR differs 

for new stationary sources and for 

modifications to existing stationary 

sources. A new source is subject to 

major NSR permitting requirements if 

its potential to emit (PTE) any regulated 

NSR pollutant equals or exceeds the 

statutory emission threshold. For 

sources in attainment areas, the major 

source threshold is either 100 or 250 

tons per year, depending on the type of 

source.43 The major source threshold for 

sources in nonattainment areas is 

generally 100 tons per year, although 

lower thresholds apply to sources 

located in areas classified at higher 

levels of nonattainment. 

A modification at an existing major 

source is subject to major NSR 

permitting requirements when it is a 

‘‘major modification,’’ which occurs 

when a source undertakes a physical 

change or change in method of 

operation (i.e., a ‘‘project’’) 44 that would 

result in both (1) a significant emissions 

increase from all emission units that are 

part of the project, and (2) a significant 

net emissions increase from the source, 

which is determined by a source-wide 

analysis that considers creditable 

emission increases and decreases 

occurring at the source as a result of 

other projects over a 5-year 

contemporaneous period. See, e.g., 40 

CFR 52.21(b)(2)(i). For this analysis, the 

NSR regulations define emissions rates 

that are ‘‘significant’’ for each NSR 

pollutant. See, e.g., 40 CFR 52.21(b)(23). 

In calculating the emissions increase 

that will result from a proposed project, 

existing NSR regulations require a 

comparison of the ‘‘projected actual 

emissions’’ (PAE) to the ‘‘baseline actual 

emissions’’ (BAE). The PAE is currently 

defined as the maximum annual rate 

that the modified unit is projected to 

emit a pollutant in any one of the 5 

years (or 10 years if the design capacity 

increases) after the project, excluding 

any increase in emissions that (1) is 

unrelated to the project, and (2) could 

have been accommodated during the 

baseline period (commonly referred to 

as the ‘‘demand growth exclusion’’). 

See, e.g., 40 CFR 52.21(b)(41). For 

electric utility steam generating units 

(EUSGU), the BAE is defined as the 

average annual rate of actual emissions 

during any 24-month period within the 

last 5 years. See, e.g., 40 CFR 

52.21(b)(48)(i). For non-EUSGUs, the 

BAE is defined the same as for EUSGUs, 

except that the 24-month period can be 

within the last 10 years. See, e.g., 40 

CFR 52.21(b)(48)(ii).45

As noted above, new stationary 

sources and modifications of stationary 

sources that do not require a major NSR 

permit may instead require a minor NSR 

permit prior to construction. Minor NSR 

permits are primarily issued by state 

and local air agencies. Minor NSR 

requirements are approved into an 

implementation plan in order to achieve 

and maintain national ambient air 

quality standards (NAAQS). See CAA 

section 110(a)(2)(C).46 The Act, EPA 

regulations and EPA guidance each 

specify minor NSR requirements, 

although the requirements are not as 

prescriptive as those covering the major 

NSR program. This reduced specificity 

affords agencies flexibility in designing 

their minor NSR programs. Since the 

minor NSR program deals with smaller 

sources and smaller increases in air 

pollution, the control requirements that 

are identified for a minor NSR permit 

tend to be less stringent than a BACT or 

LAER requirement for a major NSR 

permit. In addition, the time to process 

a permit for a minor NSR source or a 

minor modification is generally faster 

than for a major NSR permit, due to 

having fewer requirements. 

B. Interaction of NSR and the ACE Rule 

Since emission guidelines that are 

established pursuant to CAA section 

111(d) apply to units at existing sources, 

the way in which the NSR programs 

treat modifications of existing sources is 

implicated by implementation of a CAA 

section 111(d) program. Specifically, in 

complying with the emission 

guidelines, a state agency may develop 


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47See, e.g., Comments of Florida Municipal Elec 

Association on the U.S. Environmental Protection 

Agency’s ANPRM entitled, ‘‘State Guidelines for 

Greenhouse Gas Emissions from Existing Electric 

Utility Generating Units,’’ 82 FR 61507 (December 

28, 2017) at 11 (EPA–HQ–OAR–2017–0545–0155); 

see also https://www.eia.gov/todayinenergy/ 

detail.php?id=7590. 

48Electric Power Research Institute comments 

U.S. Environmental Protection Agency’s Proposed 

Rule ‘‘Carbon Pollution Emissions Guidelines for 

Existing Stationary Sources: Electric Utility 

Generating Units,’’ 79 FR 34830 (June 18, 2014) at 

12–13 (EPA–HQ–OAR–2013–0602–21697). 

a CAA section 111(d) plan that results 

in an affected source undertaking a 

physical or operational change. As 

explained above, under the NSR 

program undertaking a physical or 

operational change may require that the 

source obtain a preconstruction permit 

for the proposed change, with the type 

of NSR permit depending on the amount 

of the emissions increase resulting from 

the change and the air quality at the 

location of the source. Thus, a source 

that is adding equipment or otherwise 

making changes to its facility, on either 

its own volition or to comply with a 

national or state level requirement, will 

typically need some type of NSR permit 

prior to making such changes to its 

facility. EPA sought to exempt 

environmentally beneficially pollution 

control projects from NSR requirements 

in a 2002 rule that codified longstanding 

EPA policy, but this rule was struck 

down in court. New York v. EPA, 413 

F.3d 3, 40–42 (DC Cir. 2005) (New York 

I). 

With respect to the proposed action, 

should it be promulgated, states will be 

called upon to develop a section 111(d) 

plan that evaluates BSER technologies 

for each of their EGU sources and 

assigns emission reduction compliance 

obligations to their affected EGUs. 

Assuming the promulgated action 

adopts the same form as this proposal, 

the state may require a source with an 

affected EGU to achieve a HRI of a 

specified percentage. As described in 

Section VI.B of this preamble, a HRI 

project is designed to lower the heat rate 

of the EGU, which correlates to the unit 

consuming less fuel per kWh and 

emitting lower amounts of CO2 (and 

other air pollutants) per kWh generated 

as compared to a less efficient unit. 

Along with this increase in energy 

efficiency, the EGU which undergoes 

the HRI project will typically experience 

greater unit availability and reliability, 

all of which contribute to lower 

operating costs. EGUs that operate at 

lower costs are generally preferred in 

the dispatch order by the system 

operator over units that have higher 

operational costs,47 and EPA’s 

regulatory impact analysis (RIA) for this 

action (located in the docket) shows that 

improving an EGU’s heat rate will lead 

to increased generation due to its 

improved efficiency and relative 

economics. As the EGU increases its 

generation, to the extent the EGU 

operates beyond its historical levels by 

a meaningful amount, it could result in 

an increase in emissions on an annual 

basis, as calculated pursuant to the 

current NSR regulations. Specifically, if 

a source is undertaking a HRI project 

and its future emissions (i.e., PAE) are 

projected to increase above its historical 

emissions (i.e., BAE) in an amount 

greater than the relevant ‘‘significant’’ 

level, the source could be required to 

obtain a major NSR permit for the 

modification. 

Thus, it is possible that a source 

undertaking a HRI project at its EGU 

would project, or actually experience, 

an increase in operation of its EGU and 

a corresponding increase in annual 

emissions. This would require the 

source, at a minimum, to conduct an 

analysis to determine whether the 

project by itself is projected to lead to 

a significant emissions increase (at step 

one of the two-step analysis that 

determines whether a project constitutes 

a ‘‘major modification’’). If so, the 

source would have to conduct a netting 

analysis to determine whether there is 

also a significant net increase when 

contemporaneous increases and 

decreases from other projects are 

considered (step two of that analysis). If 

both of these types of increases would 

be projected to occur, this could result 

in the source being subject to additional 

pollutant control requirements (e.g., 

BACT or LAER), in addition to the 

substantial extra time and cost of 

applying for a major NSR permit prior 

to undertaking the HRI project. Such 

could be the consequence despite the 

fact that the project would lower the 

EGU’s output-based emissions rate for 

its air pollutants, and despite the fact 

that the resulting effect on the dispatch 

order could yield an emission reduction 

from a system-wide standpoint. 

Similarly, over the years, some 

stakeholders have asserted that the NSR 

rules discourage companies from 

exercising the discretion to undertake 

energy efficiency improvement projects, 

which they assert results in less 

environmentally protective outcomes 

from a system-wide standpoint. 

Stakeholders have claimed that 

triggering major NSR permitting 

requirements can increase the costs of 

beneficial plant improvement projects, 

like HRIs, and often contribute to a 

company’s decision to forego the 

projects. For instance, a commenter on 

the CPP proposal stated that ‘‘many 

coal-fired plants may refrain from 

making improvements based on the 

financial risk associated with 

potentially triggering a New Source 

Review, which may result in the 

requirement to invest in additional 

emissions controls . . . . [T]he 

[permitting] requirements could 

increase costs of potential heat rate 

improvements and therefore are a 

potential impediment which should be 

recognized in the rule’s calculations.’’ 48

In promulgating the CPP, EPA noted 

that these stakeholders expressed 

concerns of the potential NSR 

permitting effects from a state 

implementing the rule, stating ‘‘[w]hile 

there may be instances in which an NSR 

permit would be required, we expect 

those situations to be few . . . states 

have considerable flexibility in selecting 

varied measures as they develop their 

plans to meet the goals of the emission 

guidelines. One of these flexibilities is 

the ability of the state to establish 

emission standards in their CAA section 

111(d) plans in such a way so that their 

affected sources, in complying with 

those standards, in fact would not have 

emissions increases that trigger NSR. To 

achieve this, the state would need to 

conduct an analysis consistent with the 

NSR regulatory requirements that 

supports its determination that as long 

as affected sources comply with the 

emission standards in their CAA section 

111(d) plan, the source’s emissions 

would not increase in a way that trigger 

NSR requirements.’’ 80 FR 64920 

(October 23, 2015). The CPP also 

explained that sources can voluntarily 

take enforceable limits on hours of 

operation, in the form of a synthetic 

minor source limitation, in order to 

avoid triggering major NSR 

requirements that would otherwise 

apply to the source. 80 FR 64781, 64920. 

However, these concerns regarding 

the applicability of NSR take on even 

greater significance and may not be as 

easily avoided in the context of this 

proposed rule, which constrains the 

compliance options available in the CPP 

to within-the-fenceline measures and 

may therefore more directly result in 

individual sources making HRIs. 

Individuals within the academic 

community have examined the NSR 

interplay with making efficiency gains 

at existing coal plants. A 2014 report 

projected that 80 percent of non-retiring 

coal-fired units have emissions rates for 

NOX and SO2 at levels that exceed those 

typically required under NSR and 

concluded that the units would have to 

install additional controls for NOX or 

sulfur dioxide (SO2) if these HRI 

projects triggered the applicability of 


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49Sarah K. Adair, David C. Hoppock, Jonas J. 

Monast (from Duke University’s Nicholas Institute 

for Environmental Policy Solutions and School of 

Law, ‘‘New Source Review and coal plant efficiency 

gains: How new and forthcoming air regulations 

affect outcomes’’; Elsevier, Energy Policy 70 (2014), 

183–192. 

50Edison Electric Institute comments on the U.S. 

Environmental Protection Agency’s ANPRM 

entitled, ‘‘State Guidelines for Greenhouse Gas 

Emissions from Existing Electric Utility Generating 

Units,’’ 82 FR 61507 (December 28, 2017) at 22 

(EPA–HQ–OAR–2017–0545–0221). 

51 General Electric Company (GE) comments on 

the U.S. Environmental Protection Agency’s 

ANPRM entitled, ‘‘State Guidelines for Greenhouse 

Gas Emissions from Existing Electric Utility 

Generating Units,’’ 82 FR 61507 (December 28, 

2017) at 29–30 (EPA–HQ–OAR–2017–0545–0271). 

52 Id. at 30. 

53See, e.g., Ohio Environmental Protection 

Agency comments on the U.S. Environmental 

Protection Agency’s ANPRM entitled, ‘‘State 

Guidelines for Greenhouse Gas Emissions from 

Existing Electric Utility Generating Units,’’ 82 FR 

61507 (December 28, 2017) at 9, 32 (EPA–HQ– 

OAR–2017–0545–0246). 

54 GE comments, supra note at 33. 

55 Indiana Municipal Power Agency comments on 

the U.S. Environmental Protection Agency’s 

ANPRM entitled, ‘‘State Guidelines for Greenhouse 

Gas Emissions from Existing Electric Utility 

Generating Units,’’ 82 FR 61507 (December 28, 

2017) at 3 (EPA–HQ–OAR–2017–0545–0204). 

56Natural Resources Defense Council comments 

on the U.S. Environmental Protection Agency’s 

ANPRM entitled, ‘‘State Guidelines for Greenhouse 

Gas Emissions from Existing Electric Utility 

Generating Units,’’ 82 FR 61507 (December 28, 

2017) at 14–17 (EPA–HQ–OAR–2017–0545–0358). 

57New York v. EPA, 413 F.3d 3, 41 (D.C. Cir. 

2005) (New York I) (citing Sierra Club v. EPA, 129 

F.3d 137, 140 (D.C. Cir. 1997)). 

NSR.49 For these units then, the 

potential requirement to undertake a 

HRI to satisfy 111(d) may result in 

substantial time, effort, and money to 

comply with the requirements of major 

NSR. In addition, the potential need to 

permit so many of the projects being 

required under a 111(d) plan could 

substantially increase the burden for 

permit agencies in processing permit 

applications. To help reduce the effect 

this may have on the effective and 

prompt implementation of a revised 

CAA section 111(d) standard for EGUs, 

EPA is proposing revisions to the NSR 

regulations in this action. 

C. ANPRM Solicitation and Comments 

Received 

Through the ANPRM, EPA took 

comment on the topic of how the NSR 

program overlays with emission 

guidelines established under CAA 

section 111(d). EPA specifically 

acknowledged the concerns raised 

previously by stakeholders regarding the 

potential for a source to make energy 

efficient improvements that could 

trigger major NSR requirements. 

Furthermore, as EPA did in the CPP, 

EPA described current approaches 

available within the NSR program to 

avoid triggering NSR requirements. 

These include the ability for a source to 

obtain a synthetic minor source 

limitation, which restricts its hours of 

operation and its emissions below major 

NSR levels, and the Plantwide 

Applicability Limit (PAL), which allows 

a source to operate within a source-wide 

emissions cap to avoid triggering NSR 

for changes. 

The ANPRM solicited input on 

possible actions that EPA can take to 

harmonize and streamline the NSR 

applicability or the NSR permitting 

processes for an amended rule. EPA 

requested comment on ways to 

minimize the impact of the NSR 

program on the implementation of a 

performance standard for EGU sources 

under CAA section 111(d), specifically 

asking ‘‘[w]hat rule or policy changes or 

flexibilities can EPA provide as part of 

the NSR program that would enable 

EGUs to implement projects required 

under a CAA section 111(d) plan and 

not trigger major NSR permitting while 

maintaining environmental 

protections?’’ 82 FR 61519 (Dec. 28, 

2017). 

Several ANPRM commenters 

reiterated concerns that were raised on 

the CPP proposal regarding the NSR 

program—specifically that, if an air 

agency, as part of its plan to comply 

with emission guidelines established 

pursuant to CAA section 111(d), 

requires an affected source to make 

modifications (e.g., HRI projects), it 

could potentially trigger major NSR 

requirements. Some commenters alleged 

that the NSR program unfairly treats 

sources that are undertaking changes to 

become more energy efficient by 

requiring a costly and time consuming 

permitting burden. As expressed by one 

industry representative, ‘‘EGUs engaging 

in HRI projects can face NSR preconstruction permitting requirements 

consisting of, at a minimum, costly, 

detailed analyses and permitting delays. 

In some cases, this has resulted in costly 

and protracted litigation, and expensive 

new emission control requirements, 

both of which result in substantial time 

delays for these projects. These 

concerns remain should unit operators 

pursue HRI upgrades . . . that could 

trigger NSR in an effort to comply with 

. . . revised CAA section 111(d) GHG 

emissions guidelines.’’ 50 Another 

commenter noted that the major NSR 

permitting process ‘‘is time and resource 

intensive’’ and, including pre-permit 

application work, ‘‘can take as long as 

3 years or longer.’’ 51 The same 

commenter noted that ‘‘[the] uncertainty 

of permit timing can hinder investment 

decisions as much as the actual permit 

schedule delays.’’ 52 Some commenters 

indicated that the current flexibilities 

offered within the NSR program are not 

sufficient to avoid placing a significant 

permitting burden on EGUs and 

permitting agencies, which could result 

in substantial delays during the planned 

implementation stage.53 To avoid such 

outcomes, a number of commenters 

suggested that EPA undertake actions to 

clarify or change the NSR regulations, 

including, for example, revising the 

NSR modification applicability to be 

based on pounds per kilowatt-hour (lb/ 

kW-h) 54 or rejecting as BSER any 

project that would result in triggering 

NSR.55

However, other commenters 

disagreed. For instance, the Natural 

Resources Defense Council (NRDC) 

suggested that changes to the NSR 

program ‘‘are unwarranted.’’ 56 They 

added that EPA needs to remain in the 

boundary of the controlling judicial 

decisions in considering what 

approaches could be used to reduce the 

number of existing sources that will be 

subject to NSR permitting while crafting 

CAA section 111(d) plans. NRDC 

focused the basis of many of its 

concerns on the court’s opinion in New 

York v. EPA, 443 F.3d 880 (D.C. Cir. 

2006) (New York II), which vacated 

EPA’s attempt to more clearly define 

‘‘routine maintenance, repair, and 

replacement’’ (RMRR) projects that are 

exempt from major NSR by EPA’s rules. 

NRDC also referenced the following 

observation from an earlier decision by 

the same court that vacated the 

‘‘pollution control project exclusion’’ 

that EPA finalized in 2002: ‘‘Absent 

clear congressional delegation, however, 

EPA lacks authority to create an 

exemption from NSR by administrative 

rule.’’ 57

D. Proposing NSR Changes for Improved 

ACE Implementation 

1. Overview 

EPA acknowledges the NSR program 

may have unintended consequences for 

implementation of this emission 

guidelines for GHG emissions from 

existing EGUs. Based on the comments 

received on the ANPRM and EPA’s 

experience with the NSR program 

generally, EPA recognizes the potential 

for triggering major NSR permitting 

when sources undertake HRI projects. 

EPA further recognizes that the prospect 

of a protracted permitting process and a 

possible requirement to install pollution 

control equipment at the emissions unit 

can create a disincentive for sources to 

voluntarily make energy efficiency 


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58 In May 2001, President Bush’s National Energy 

Policy Development Group issued findings and key 

recommendations for a National Energy Policy. This 

document included numerous recommendations for 

action, including a recommendation that the EPA 

Administrator, in consultation with the Secretary of 

Energy and other relevant agencies, review NSR 

regulations, including administrative interpretation 

and implementation. The recommendation 

requested that EPA issue a report to the President 

on the impact of the regulations on investment in 

new utility and refinery generation capacity, energy 

efficiency, and environmental protection. The 

report to the President was issued on June 13, 2002, 

and is available at https://www.epa.gov/nsr/newsource-review-report-president. In the report to the 

President, EPA concluded ‘‘[as] applied to existing 

power plants and refineries . . . the NSR program 

has impeded or resulted in the cancellation of 

projects which would maintain and improve 

reliability, efficiency and safety of existing energy 

capacity. Such discouragement results in lost 

capacity, as well as lost opportunities to improve 

energy efficiency and reduce air pollution.’’ New 

Source Review Report to the President at 3. 

improvements. Many of these concerns 

with the NSR program were raised 

nearly two decades ago, and formed the 

cornerstone of EPA’s initiative in the 

early 2000’s to reform the NSR 

program.58

But this dynamic takes on a new 

character in the context of a regulation 

that may result in a source undertaking 

a HRI or another project to meet a 

standard of performance as determined 

by the state. When a state’s 111(d) plan 

requires an EGU to comply with a 

standard of performance, sources cannot 

choose to forego a project in an effort to 

avoid NSR permitting as they could 

with improvement projects they were 

otherwise considering. Despite recent 

actions by EPA to streamline the NSR 

program, the reality remains that a 

source that undertakes a HRI project 

may trigger major NSR under the 

current NSR applicability test when 

required to undertake a HRI project as 

part of a state’s 111(d) plan. As has been 

noted by commenters on the ANPRM, 

this can require the source to undertake 

significant planning and analysis with 

the process to receive a preconstruction 

permit, sometimes taking 3 or more 

years. This added time and cost to 

sources and the associated burden on 

permitting agencies could hinder the 

effective and prompt implementation of 

state 111(d) plans. 

In this context, our approach in the 

CPP of encouraging agencies to 

minimize the triggering of major NSR 

for their affected EGUs by conducting 

emissions analyses as part of their CAA 

section 111(d) plan development does 

not appear to be a sufficient solution. 

While EPA supports states having the 

primary authority to implement the air 

programs, state agencies should not be 

burdened with having to determine a 

‘‘work around’’ for the NSR program 

requirements in developing their plans 

to implement the emission guidelines 

for affected EGUs. The responsibility of 

ensuring that emission guidelines under 

111(d) are clearly articulated and easily 

implementable rests squarely with EPA. 

Thus, EPA addressing the time delays 

and costs that can result from NSR 

requirements could be one tool for 

helping ensure the successful 

implementation of a national program 

for controlling GHG emissions from 

existing EGUs. 

It is important for a state that is 

developing a CAA section 111(d) plan to 

completely understand the full costs 

being imposed on their affected sources 

in order for the state to make informed 

decisions in applying a standard of 

performance to each of their existing 

sources (much like a state would 

consider, among other factors, the 

remaining useful life of each source). 

However, EPA has historically not 

considered the costs of complying with 

other CAA programs, like NSR, when 

determining BSER for a source category 

under section 111. This was in part 

because, for many years, EPA applied a 

policy of excluding pollution control 

projects from NSR. But, as noted earlier 

in this section, EPA’s attempt to codify 

such a policy in the NSR regulations 

was struck down by the D.C. Circuit in 

2005. Since that decision, EPA has not 

written a significant number of rules 

under section 111, and the rules that 

EPA has written have not presented a 

need to consider this question. 

However, due to the nature of the 

electric utility industry and the types of 

candidate control measures being 

considered in this proposal, it may be 

appropriate to consider NSR compliance 

costs in this instance. Specifically, the 

BSER measures chosen in this rule may 

result in a source undertaking a physical 

change that significantly increases its 

annual emissions and triggers major 

NSR permitting requirements such that 

permitting costs are unavoidable. 

However, due to the case-specific 

analysis required to determine NSR 

applicability, it would likely be difficult 

for a state to adequately predict and 

quantify the effect of a HRI on an EGU’s 

operational costs, change in dispatch 

order, and other variables that would 

factor into whether the source needs a 

major NSR permit or, perhaps, a minor 

NSR permit. In addition, even if a state 

can reasonably predict an EGU’s 

emissions increase resulting from a HRI 

project such that it can expect the 

source will need a major NSR permit, it 

would likely be difficult to predict the 

expected permitting costs since the 

emission control and other permitting 

requirements are case-by-case 

determinations and can therefore vary 

significantly due to a number of factors, 

including how well the source is 

already controlled, the emissions from 

nearby sources and their contribution to 

air quality concerns, whether the source 

is located in an attainment or 

nonattainment area, and the potential 

for the air permit to trigger other 

requirements (e.g., Endangered Species 

Act, National Historic Preservation Act). 

In some cases, a source triggering major 

NSR may be required to conduct 

extensive modeling and install 

additional pollution controls for nonGHG pollutants. Thus, the case-by-case 

nature of the NSR program can lead to 

uncertainty for a state that is creating its 

111(d) plan and wanting to ensure that 

the plan fully appreciates the projected 

compliance costs for its affected EGUs. 

EPA is, therefore, inviting comment 

on whether it is appropriate to consider 

the costs of NSR compliance in the 

BSER analysis under section 111(d), 

assuming that triggering NSR cannot 

otherwise be avoided through actions by 

the source or through revisions to the 

NSR regulations that are proposed by 

EPA in this rule or if EPA does not 

finalize revisions to the NSR regulations 

(Comment C–59). In addition, EPA 

solicits comment on how a state or local 

permitting agency may estimate or 

project the cost for the source to comply 

with any NSR requirements that may 

flow from a selected BSER, and on how 

the potential for delays because of an 

influx of NSR permit applications may 

be accounted for in setting an 

implementation schedule for 111(d) 

plans (Comment C–60). 

Recognizing that EPA issuing this 

111(d) rule would mean that a source 

may no longer be in a position to forego 

a HRI project due to unwanted 

permitting costs, EPA has continued to 

look for ways to reduce the costs of NSR 

requirements, while being mindful of 

the requirements of the CAA and the 

court decisions on prior NSR reform 

rules that were referenced by some 

commenters. In this light, EPA believes 

that a past option for revising the NSR 

regulation that EPA has considered may 

warrant further consideration to address 

this concern. In 2005 and 2007, EPA 

previously proposed adopting an hourly 

emissions rate test for NSR applicability 

for EGUs. While this rulemaking was 

never completed, EPA believes that it 

warrants a fresh look in a new context 

here where NSR program flexibility 

takes on added significance as a means 

to facilitate the HRI projects that are 

expected to be undertaken should the 

proposed ACE rule be finalized. This 

same idea was also raised by a few 


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59See, e.g., Arizona Public Service Company 

comments on the U.S. Environmental Protection 

Agency’s ANPRM entitled, ‘‘State Guidelines for 

Greenhouse Gas Emissions from Existing Electric 

Utility Generating Units,’’ 82 FR 61507 (Dec. 28, 

2017) at 6 (EPA–HQ–OAR–2017–0545– 

0286);Unions for Jobs & Environmental Progress 

comments on the U.S. Environmental Protection 

Agency’s ANPRM entitled, ‘‘State Guidelines for 

Greenhouse Gas Emissions from Existing Electric 

Utility Generating Units,’’ 82 FR 61507 (Dec. 28, 

2017) at 14–17 (EPA–HQ–OAR–2017–0545–0162). 

60See supra note. 

commenters on the ANPRM.59 Thus, 

EPA is soliciting comment on whether 

a narrower range of options for 

implementing an hourly emissions test 

for NSR for EGUs would both help 

promote energy efficiency and the 

effectiveness of implementing the ACE 

rule, while at the same time being 

consistent with the NSR provisions in 

CAA and past judicial decisions 

interpreting those provisions (Comment 

C–61). 

2. The 2007 Supplemental Rule 

Proposal 

In 2007, EPA proposed to revise the 

NSR provisions to include an NSR 

applicability test for EGUs that is based 

on maximum hourly emissions. 72 FR 

26202 (May 8, 2007). The 2007 

proposed action was a ‘‘supplemental’’ 

notice of proposed rulemaking 

(SNPRM), because the 2007 proposal 

followed an earlier action by EPA that 

proposed a more limited form of the 

hourly emissions test for NSR 

applicability. 70 FR 61081 (October 20, 

2005) (NPRM). These proposals 

followed EPA’s NSR regulatory reform 

efforts of 2002 and 2003, when EPA 

promulgated final regulations that 

implemented several of the 

recommendations in the New Source 

Review Report to the President.60 Those 

earlier regulatory actions, however, left 

the NSR provisions for electric utilities 

largely unchanged. 

The 2007 SNPRM requested comment 

on two basic options, and various 

alternatives within each of the two 

options, for changing the test for 

determining an emissions increase from 

an EGU undergoing a physical or 

operational change. The proposal 

included emissions test alternatives 

based on an EGU’s maximum achieved 

hourly emissions rate—applying either a 

‘‘statistical approach’’ or a ‘‘one-in-5- 

year baseline approach’’—and an EGU’s 

maximum achievable hourly emissions 

rate, which mirrored the NSPS 

modification applicability test. While 

EPA did not propose rule amendments 

in the 2005 NPRM, in 2007 EPA 

proposed to amend 40 CFR part 51 to 

include a new provision at § 51.167, 

which largely mirrored the NSPS 

modification provisions in § 60.2 and 

§ 60.14. The 2007 SNPRM provided 

EPA’s legal and policy basis for 

incorporating an hourly emissions 

increase test within the NSR program 

for EGUs. 

For the proposed maximum achieved 

hourly test alternatives, an EGU owner/ 

operator would determine whether an 

emissions increase would occur by 

comparing the pre-change maximum 

actual hourly emissions rate to a 

projection of the post-change maximum 

actual hourly emissions rate. In 

establishing the baseline, both 

alternatives considered the unit’s actual 

performance during the 5-year period 

immediately preceding the physical or 

operational change. For the one-in-5- 

year baseline approach, the emissions 

rate would be computed based on what 

the unit actually achieved for any single 

hour within the 5-year period 

immediately before the physical or 

operational change. For the statistical 

approach, the owner/operative would 

analyze continuous emission 

monitoring system (CEMS) or predictive 

emission monitoring system (PEMS) 

data from the 5 years preceding the 

physical or operational change to 

determine the maximum actual 

pollutant emissions rate. The statistical 

approach would utilize actual recorded 

data from periods of representative 

operation to calculate the maximum 

actual emissions rate associated with 

the pre-change maximum actual 

operating capacity in the past 5 years. 

The purpose behind developing the 

statistical approach was to address 

concerns from comments received on 

the 2005 NPRM ‘‘that maximum 

achievable emissions could differ from 

maximum achieved emissions for a 

given EGU for any given period as a 

result of factors independent of the 

physical or operational change, 

including variability of the sulfur 

content in the coal being burned.’’ 72 FR 

26219 (May 8, 2007). In the 2007 

SNPRM, EPA acknowledged that the 

highest hourly emissions do not always 

occur at the point of highest capacity 

utilization, due to fluctuations in 

process and control equipment 

operation, as well as in fuel content and 

firing method. The proposed statistical 

procedure would consequently ensure 

that the maximum achieved hourly 

emissions test identified the maximum 

hourly pollutant emissions value. 

Specifically, the statistical procedure 

would estimate the highest value (99.9 

percentage level) in the period 

represented by the data set compiled 

from hourly average CEMS or PEMS 

measured emission rates and 

corresponding heat input data. EPA 

asserted that this approach would 

mitigate some of the uncertainty 

associated with trying to identify the 

highest hourly emissions rate at the 

highest capacity utilization. EPA 

asserted then that ‘‘over a period that is 

representative of normal operations, in 

general the maximum achievable and 

maximum achieved hourly emissions 

test would lead to substantially 

equivalent results.’’ 72 FR 26220. 

For the proposed maximum 

achievable hourly test alternatives, the 

major NSR regulations would apply at 

an EGU if a physical or operational 

change results in any increase above the 

maximum hourly emissions achievable 

at that unit during the 5 years prior to 

the change. Pre-change and post-change 

hourly emissions rates would be 

determined according to the NSPS 

provisions in § 60.14(b). Hourly 

emission increases would be 

determined using emission factors, 

material balances, continuous monitor 

data, or manual emission tests. 

In the 2007 SNPRM, EPA argued that 

a maximum hourly emissions test 

would simplify major NSR applicability 

determinations and implementation. 

EPA contended that ‘‘the achieved and 

achievable [hourly emissions] tests 

eliminate the burden of projecting 

future emissions and distinguishing 

between emissions increases caused by 

the change from those due solely to 

demand growth, because any increase in 

the emissions under the hourly 

emissions tests would logically be 

attributed to the change. Both the 

achieved and achievable tests reduce 

recordkeeping and reporting burdens on 

sources because compliance will no 

longer rely on synthesizing emissions 

data into rolling average emissions.’’ 72 

FR 26206 (May 8, 2007). 

While the 2005 action had proposed 

to replace the current NSR annual 

emissions increase test with an hourly 

test, the 2007 action proposed the same 

option as well as an option to retain the 

annual emissions test along with an 

hourly test. For the combined hourly 

and annual emissions option, if a 

change would not increase the hourly 

emissions of the EGU, major NSR would 

not apply; however, if hourly emissions 

would increase after the change, then 

projected annual emissions would be 

reviewed using the existing NSR 

applicability test. The 2007 SNPRM 

expressed a preference for this 

combined applicability option. 

In the 2007 SNPRM, the proposed 

changes to the NSR emissions test were 

in part justified by the substantial EGU 

emission reductions from other air 

programs enacted since 1980 and the 

capped emissions approaches used for 


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61To this point, as Justice Thomas explains, the 

majority’s analysis of the relationship between the 

NSR and NSPS programs is dicta, because the NSR 

regulations, as then written, could not be 

permissibly read to mean the same as the NSPS 

regulations, and CAA section 307(b) prohibits 

review of the NSR regulations in the context of an 

enforcement action. Duke Energy, 549 U.S. at 582 

(Thomas, J. concurring) (explaining that Justice 

Thomas joins only Part III.B of the majority 

opinion). 

SO2 and nitrogen oxides (NOX) since the 

CAA Amendment of 1990. The analyses 

conducted for that 2007 SNPRM 

concluded that, by 2020, more EGUs 

would install controls than they would 

in complying with a number of emission 

cap-based EPA rules that were in play 

at the time (i.e., Clean Air Interstate 

Rule, Clean Air Mercury Rule, and 

Clean Air Visibility Rule). The analysis 

maintained that the hourly emissions 

test would allow units to operate more 

hours each year, and the more hours a 

unit operates, the more it will control 

emissions to remain under the emission 

caps. It concluded that there would be 

essentially no changes in national 

emissions of SO2 and NOX by coal-fired 

power plants, and essentially no impact 

on county-level emissions or local air 

quality. 

These 2005 and 2007 proposed rules 

were neither finalized nor withdrawn by 

EPA. The rulemaking docket for these 

actions is EPA–HQ–OAR–2005–0163. 

3. Legal Basis for Using Hourly 

Emission Rates To Identify Increases in 

Emissions 

The 2007 SNPRM followed EPA’s 

NPRM from 2005 that would have 

replaced the NSR program’s annual 

emissions test with an hourly test. The 

proposed regulatory approach taken in 

2005 was based on the decision in 

United States v. Duke Energy Corp., 411 

F.3d 539 (4th Cir. 2005), in which the 

court held that the NSPS and NSR 

programs must have a uniform 

emissions test. There, in the context of 

an NSR enforcement case, the meaning 

of the CAA’s definition of 

‘‘modification,’’ and the proper 

interpretation of the provisions of the 

NSR regulations (as promulgated in 

1980) that spoke to how an ‘‘emissions 

increase’’ was to be determined were at 

issue. The Fourth Circuit held that the 

CAA requires that those NSR 

regulations ‘‘conform’’ to their NSPS 

counterpart. 411 F.3d at 548. According 

to the Fourth Circuit, because Congress 

had relied on a cross-reference to CAA 

section 111(a)(4)’s definition of 

‘‘modification’’ (i.e., the original NSPS 

definition) to define ‘‘modification’’ for 

purposes of the NSR program, this 

created an ‘‘effectively irrebuttable 

presumption’’ that the two definitions 

must be the same.’’ Id. at 550. 

The case then went to the Supreme 

Court, and the Supreme Court 

disagreed. In Environmental Defense v. 

Duke Energy Corporation, 549 U.S. 561 

(2007), the Supreme Court held that 

there was ‘‘no effectively irrebuttable 

presumption that the same defined term 

in different provisions of the same 

statute must be interpreted identically. 

Context counts.’’ 549 U.S. at 575–76 

(internal citation and quotation marks 

omitted). Moving beyond the procedural 

question of whether the Fourth Circuit 

had applied the proper tools of statutory 

construction, the Court also engaged the 

underlying substantive question, finding 

that ‘‘[n]othing in the text or the 

legislative history’’ suggests that 

Congress intended to require that the 

programs be tied together and thereby 

‘‘eliminat[e] the customary agency 

discretion to resolve questions about a 

statutory definition by looking to the 

surroundings of the defined term.’’ Id. at 

576. 

Of particular significance here, the 

Supreme Court also addressed the 

possibility that the two regulatory 

programs could be read together as set 

and subset, such than an NSPS-type 

modification was a prerequisite to an 

NSR-type modification—i.e., that 

‘‘before a project can become a ‘major 

modification’ under the PSD 

regulations, it must meet the definition 

of ‘modification’ under the NSPS 

regulations.’’ 549 U.S. at 581 n.8. This 

reading ‘‘sounds right,’’ the Court 

opined,’’ but then observed that, in its 

view, the NSPS and NSR regulations as 

they were then written did not support 

such a reading. Id. Although the Court 

had no occasion to address whether the 

Clean Air Act allows, rather than 

directs, EPA to define ‘‘modification’’ 

the same way in both the NSPS and 

NSR programs, EPA believes that the 

answer is clearly yes. The Court does 

generally ‘‘presume that the same term 

has the same meaning when it occurs 

here and there in a single statute,’’ 549 

U.S. at 575, and, as Justice Thomas 

pointed out in his concurrence, in the 

case of the CAA’s definition of 

‘‘modification,’’ Congress’s use of a 

cross-reference ‘‘carries more meaning 

than mere repetition of the same word 

in a different statutory context.’’ Id. at 

583 (Thomas, J., concurring).61

In the 2007 SNPRM, EPA argued that 

the Supreme Court decision left room 

for EPA to revise the regulations when 

it has a rational basis for doing so. 72 

FR 26202, 26204 (May 8, 2007); see also 

Environmental Defense v. Duke Energy 

Corp., 549 U.S. 561, 576 (2007) (‘‘EPA’s 

construction [of the definition of 

modification] need do no more than fall 

within the limits of what is reasonable, 

as set by the Act’s common definition.’’) 

EPA also argued that a maximum hourly 

emissions test for NSR is an appropriate 

exercise of EPA’s discretion citing 

Chevron U.S.A., Inc. v. NRDC, Inc. 467 

U.S. 37,865 (1984). Chevron provides 

that when a statute is silent or 

ambiguous with respect to a specific 

issue, the relevant inquiry for a 

reviewing court is whether the Agency’s 

interpretation of the statutory provision 

is permissible. In this case, the Clean 

Air Act is silent on how to determine 

whether a physical change or change in 

method of operation ‘‘increases the 

amount of any air pollutant emitted.’’ 42 

U.S.C. 7411(a)(4); New York I, 413 F.3d 

at 22 (‘‘[T]he CAA . . . is silent on how 

to calculate such ‘increases’ in 

emissions.’’). Accordingly, EPA has 

broad discretion to propose a reasonable 

method by which to calculate the 

‘‘amount’’ of an emissions ‘‘increase’’ 

for purposes of NSR applicability. 

In the 2007 action, EPA also 

explained how an applicability test 

based on maximum achievable hourly 

emissions is, in fact, a test based on 

actual emissions. The reason is that, as 

a practical matter, ‘‘for most, if not all 

EGUs, the hourly rate at which the unit 

is actually able to emit is substantively 

equivalent to that unit’s historical 

maximum hourly emissions. That is, 

most, if not all EGUs will operate at 

their maximum actual physical and 

operational capacity at some point in a 

5-year period. In general, the highest 

emissions occur during the period of 

highest utilization. As a result, both the 

maximum achievable and maximum 

achieved hourly emissions increase tests 

allow an EGU to utilize all of its existing 

capacity, and in this aspect the hourly 

rate at which the unit is actually able to 

emit is substantively equivalent under 

both tests.’’ 72 FR 26219 (May 8, 2007). 

Thus, EPA considered the approaches 

proposed in the 2007 SNPRM to be 

consistent with the D.C. Circuit 

precedent which held that the 2002 NSR 

Reform Rule’s ‘‘Clean Unit’’ provision 

was beyond EPA’s authority because 

Congress intended to apply NSR to 

increases in actual emissions, even 

though the decision deferred to EPA on 

the method for calculating baseline 

emissions. Compare New York I, 413 

F.3d at 40 with id. at 20. In New York 

I, the D.C. Circuit found that the ‘‘Clean 

Unit’’ provision was unlawful because it 

‘‘measures ‘increases’ in terms of Clean 

Unit status instead of actual emissions.’’ 

413 F.3d at 39. In defense of the 

provision, EPA had asserted that the 

CAA is ‘‘silent’’ as to whether an 

emissions increase ‘‘must be measured 

in terms of actual emissions, potential 


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62As noted above, EPA is inviting comment 

regarding whether, if we do not address NSR 

permitting burden with this proposal, we should 

provide a mechanism for state and local permitting 

agencies to consider the costs and delays associated 

with NSR permitting. See Section VIII.C.1 of this 

preamble. 

63For clarity, this table lists all of the steps in the 

NSR major modification applicability determination 

under the three alternatives being proposed in this 

action. This current action does not propose to 

change any of the current NSR applicability steps 

besides inserting Step 2. 

emissions, or some other currency,’’ and 

that EPA was therefore owed deference 

to interpret what type of ‘‘increases’’ are 

relevant for the modification analysis. 

Id. The D.C. Circuit, however, disagreed. 

The court found that section 111(a)(4)’s 

reference to ‘‘the amount of any air 

pollutant emitted by [the] source plainly 

refers to actual emissions’’ and cannot 

encompass potential emissions. Id. at 40 

(emphases in original). According to the 

court, ‘‘the plain language of the CAA 

indicates that Congress intended to 

apply NSR to changes that increase 

actual emissions instead of potential or 

allowable emissions.’’ Id. 

At the same time, the D.C. Circuit 

affirmed that EPA has wide discretion to 

interpret the definition of 

‘‘modification’’ within these bounds. 

The court rejected challenges brought to 

the 2002 NSR Reform Rule’s then-new 

baseline period provision, finding that 

‘‘[i]n enacting the NSR program, 

Congress did not specify how to 

calculate ‘increases’ in emissions,’’ with 

the result that it was left to EPA ‘‘to fill 

that gap while balancing the economic 

and environmental goals of the statute.’’ 

413 F.3d at 27. Because the CAA is 

‘‘silent on how to calculate . . . 

‘increases’ in emissions’’ for purposes of 

determining ‘‘modification,’’ the court 

said, id. at 22, EPA has discretion to 

give meaning to that term by adopting 

a baseline period that ‘‘ ‘represents a 

reasonable accommodation of’ ’’ the 

Agency’s environmental, economic, and 

administrative concerns. Id. at 23 

(quoting Chevron, 467 U.S. at 845). The 

D.C. Circuit went on to say that 

‘‘[d]ifferent interpretations of the term 

‘increases’ may have different 

environmental and economic 

consequences,’’ and in ‘‘administering 

the NSR program and filling in the gaps 

left by Congress, EPA has the authority 

to choose an interpretation that balances 

those consequences.’’ Id. at 23–24. The 

court added that this choice may be 

informed by both EPA’s ‘‘extensive 

experience and expertise’’ in this 

technical and complex regulatory 

program and by the ‘‘incumbent 

administration’s view of wise policy.’’ 

Id at 24. 

As for NRDC’s argument in comments 

on the ANPRM that narrowing the scope 

of projects subject to NSR requirements 

would be contrary to the D.C. Circuit’s 

New York II decision, EPA notes that 

what was before the court in that case 

was an effort by EPA to further define 

what type of projects are considered 

RMRR and thus excluded from the types 

of ‘‘physical change[s] in, or change[s] 

in the method of operation of’’ a source 

that may trigger NSR. New York II, 443 

F.3d at 883. While the case focused on 

the ‘‘physical change’’ criterion of 

‘‘modification,’’ the court’s decision 

does provide some guidance on EPA’s 

discretion to interpret ‘‘emissions 

increase.’’ The court in New York II 

found that the Equipment Replacement 

Rule, as promulgated in 2003, violated 

the CAA because its bright-line RMRR 

test, which took into account the value 

of the particular components being 

replaced, was inconsistent with CAA 

section 111(a)’s broad applicability to 

‘‘any physical change’’ that results in 

increased emissions, subject to only de 

minimis exclusions. Id. at 890. But in so 

finding, the D.C. Circuit contrasted what 

it found to be the clear meaning of ‘‘any 

physical change’’ with ‘‘Congress’s use 

of the word ‘increase,’ ’’ which 

‘‘necessitated further definition 

regarding rate and measurement for the 

term to have any contextual meaning.’’ 

Id. at 888–889. Accordingly, contrary to 

NRDC’s assertions, New York II 

confirms the finding in New York I that, 

other than requiring that they be 

measured in terms of actual emissions, 

the CAA leaves to EPA the discretion to 

determine how emission increases will 

be defined for the purposes of NSR 

modification. 

4. This Proposal 

Consistent with our policy goal of 

encouraging efficient use of existing 

energy capacity and managing the 

burden on states of developing and 

implementing their CAA section 111(d) 

plans, EPA is proposing to amend the 

NSR regulations to include an hourly 

emissions increase test for EGUs. These 

proposed changes could be one tool that 

states may use to help ensure the 

efficient and effective implementation 

of their 111(d) plans.62

EPA is proposing some of the same 

alternatives for an hourly emissions test 

that EPA proposed in 2007. The 2007 

SNPRM solicited comment on 12 

alternatives, but EPA is narrowing the 

number of alternatives for this revised 

proposal and solicitation of comment. In 

this case, EPA is proposing only 

alternatives in which the hourly test is 

paired with the current NSR annual 

emissions test (i.e., Option 1 in the 2007 

SNPRM) and only the alternatives that 

have an input-based format (i.e., 

Alternatives 1, 3, and 5 in the 2007 

SNPRM). Table 1 reflects the three 

alternatives being proposed in this 

action, and how they fit within the 

structure of the proposed combined 

annual and hourly emissions test for 

NSR applicability. 

TABLE 5—PROPOSED MAJOR NSR APPLICABILITY FOR AN EXISTING EGU 63

Step 1: Physical Change or Change in the Method of Operation. 

Step 2: Hourly Emissions Increase Test. 

• Alternative 1—Maximum achieved hourly emissions; statistical approach; input basis. 

• Alternative 2—Maximum achieved hourly emissions; one-in-5-year baseline; input basis. 

• Alternative 3—Maximum achievable hourly emissions; input basis. 

Step 3: Significant Emissions Increase Determined Using the Actual-to-Projected-Actual Emissions Test as in the Current NSR Rules. 

Step 4: Significant Net Emissions Increase as in the Current NSR Rules. 

Thus, under this proposed approach, 

the major NSR program would include 

a four-step applicability process (with 

the second step inserted as proposed, 

while retaining the other steps): (1) A 

physical change or change in the 

method of operation as in the current 

major NSR regulations; (2) an hourly 

emissions increase test (either 

maximum achieved hourly emissions 

rate or maximum achievable hourly 

emissions rate, each on an input-basis 

(lb/hr)); (3) a significant emissions 

increase as in the current major NSR 

regulations; and (4) a significant net 

emissions increase as in the current 

major NSR regulations. For a major 

modification to occur, under Step 1, a 

physical change or change in the 

method of operation must occur. If there 

is a physical change or change in 


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64Analogous provisions are found in 40 CFR 

51.165, 52.21, and appendix S to 40 CFR part 51. 

65Analogous provisions are found in 40 CFR 

51.165, 52.21, and appendix S to 40 CFR part 51. 

method of operation, under Step 2, that 

change must result in an hourly 

emissions increase at the existing EGU. 

If a post-change hourly emissions 

increase is projected, a source must then 

proceed to determine whether there is 

also a significant emissions increase and 

a significant net emissions increase. In 

such cases, under Step 3, the owner/ 

operator would determine whether an 

emissions increase would occur using 

the actual-to-projected-actual annual 

emissions test as provided in the current 

regulations. There would be no 

conversion from annual to hourly 

emissions. Finally, in Step 4, as in the 

current regulations, if a significant 

emissions increase is projected to occur, 

the source would still not be subject to 

major NSR unless there was a 

determination that a significant net 

emissions increase would occur. 

This proposed approach would not 

alter the provisions in the current major 

NSR regulations pertaining to a 

significant emissions increase and a 

significant net emissions increase. 

Therefore, the NSR regulations would 

retain the definitions of net emissions 

increase, significant, projected actual 

emissions, and baseline actual 

emissions. See 40 CFR 51.166(b)(3), 

51.166(b)(23), 51.166(b)(40), 

51.166(b)(47).64 The regulations would 

also retain all provisions in the current 

regulations that refer to major 

modifications, including, but not 

limited to, those in 40 CFR 

51.166(a)(7)(i) through (iii), (b)(9), 

(b)(12), (b)(14)(ii), (b)(15), (b)(18), (i)(1) 

through (9), (j)(1) through (4), (m)(1) 

through (3), (p)(1) through (7), (r)(1) 

through (7), and (s)(1) through (4).65

To incorporate the four-step 

modification provisions, EPA is 

proposing to add two new sections to 

the major NSR program rules. The first, 

40 CFR 51.167, would specify that State 

Implementation Plans may include a 

new Step 2 for major NSR applicability 

at existing EGUs, including those for 

both attainment and nonattainment 

areas. The second, 40 CFR 52.25, would 

contain the requirements for major NSR 

applicability for existing EGUs where 

EPA is the reviewing authority or EPA 

has delegated our authority to a state or 

local air permitting agency. EPA is also 

proposing to make the same changes 

where necessary to conform the general 

provisions in parts 51 and 52 to the 

requirements of the major NSR program, 

such as in the definition of modification 

in 40 CFR 52.01. The new sections at 

§ 51.167 and § 52.25 will be separate 

and distinct from the other NSR 

provisions and this will allow our rules 

to apply this new proposed Step 2 to 

EGUs while keeping the current 

distinction in our NSR rules that applies 

different applicability requirements for 

EUSGUs and non-EUSGUs that are not 

EGUs. 

While EPA is proposing that this NSR 

hourly emissions test would apply to all 

EGUs, as defined in 40 CFR 51.124(q), 

EPA is soliciting comment on whether 

to confine the applicability of the hourly 

test to a smaller subset of the power 

sector, such as only the affected EGUs 

that are making modifications to comply 

with their state’s standards of 

performance pursuant to these section 

111(d) emissions guidelines (i.e., 

pursuant to this document’s proposed 

provisions at § 60.5775a and § 60.5780a) 

(Comment C–62). In addition, while the 

2007 SNPRM solicited comment on 

whether such a test should be limited to 

the geographic areas covered by several 

of EPA’s rules at the time, because the 

ACE rule would potentially affect EGUs 

in all of the contiguous U.S., EPA is 

proposing in this action to not limit its 

applicability to specific geographic 

areas. We are specifically proposing that 

it would apply to EGUs in all areas of 

the United States. Finally, although the 

2007 SNPRM requested comment on 

whether the proposed NSR hourly 

emissions test should be limited to 

increases of SO2 and NOX emissions 

(due to the analysis that supported the 

2007 SNPRM), EPA is proposing in this 

action that the NSR hourly emissions 

test would apply to all regulated NSR 

pollutants because the candidate 

technologies being considered under 

this proposal may affect annual 

emissions of not only GHGs but of all 

pollutants from the power sector (and 

because EPA is not relying on the 

previous proposal’s analysis that 

focused on SO2 and NOX emissions). 

EPA solicits comment on these 

approaches to applicability for the 

proposed NSR hourly emission increase 

test. 

Recognizing that existing case law 

dictates that the phrase ‘‘increases the 

amount of any air pollutant’’ in CAA 

section 111(a)(4) refers to increases in 

actual emissions for NSR purposes, in 

2007 EPA argued that an hourly 

achievable test is equivalent to a 

measure of actual emissions because 

‘‘for most, if not all EGUs, the hourly 

rate at which the unit is actually able to 

emit is substantively equivalent to that 

unit’s historical maximum hourly 

emissions.’’ 72 FR 26219 (May 8, 2007). 

EPA is taking comment on this prior 

assertion and whether recent changes to 

the energy sector may have rendered it 

invalid (Comment C–63). EPA is also 

asking for comment on whether if, 

practically speaking, maximum 

achieved and maximum achievable 

hourly rates are equivalent for most if 

not all EGUs, EPA has the flexibility 

under the CAA to implement an hourly 

achievable emissions test for NSR 

(Comment C–64). 

As noted in the preceding section, 

EPA’s proposal in 2007 to adopt an 

hourly emissions increase test for NSR 

included an analysis demonstrating that 

(1) the proposed regulations would not 

have an undue adverse impact on local 

air quality, and (2) increases in the 

hours of operation at EGUs, to the extent 

they may increase under a maximum 

hourly rate test for NSR, would not 

notably increase national SO2, NOx, 

PM2.5, VOC, or CO emissions from the 

power sector. The analysis in 2007 

concluded that the more efficiently and 

the more cost-effectively an EGU 

operates, the more likely it is to install 

controls due to other EPA air 

regulations. While time has passed since 

the analyses in the 2007 SNPRM were 

conducted, the analysis conducted for 

the ACE rule similarly reflects that, for 

scenarios that include varying levels 

and costs of efficiency improvements 

(reflecting, in part, the proposed 

changes to NSR in this action), total 

national emissions of CO2 and other 

pollutants will essentially stay the same 

or be slightly reduced when compared 

with a CPP repeal. While it is possible 

that some individual units may 

experience an increase in annual 

emissions due to increases in operation, 

it is very difficult to project with 

confidence at which of the units this 

would actually occur. This is partly due 

to the framework of the current NSR 

annual emissions test, which considers 

a number of source-specific variables— 

including operational history of the 

unit, projected emissions that may be 

exempted due to demand growth, other 

units competing for dispatch, and 

availability of creditable emission 

decreases at the facility—that could 

result in the source ultimately not being 

subject to major NSR. Consequently, the 

analysis conducted for the ACE rule 

estimates the cost and benefits of the 

different scenarios in a categorical sense 

and does not attempt to identify the 

particular sources at which major NSR 

permitting may be required absent the 

type of revisions to the NSR regulations 

proposed here or incorporate a specific 

cost for NSR permitting within any of 

the scenarios. This is due in part to 

limitations in the feasibility of such 

analysis and in part to the structure of 


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66 40 CFR 49.154(d). We note that many state (and 

local) minor NSR permitting programs have similar 

methods for ensuring that the NAAQS are 

protected. 

section 111(d) and the state-plan 

development phase which would follow 

a finalization of this proposed rule. EPA 

requests comment on the concern about 

the potential emission increases as part 

of the proposed NSR changes that some 

stakeholders have raised (Comment C– 

65). 

While recognizing that fewer sources 

will trigger major NSR under an hourly 

emissions increase, we note that even if 

a source undertaking a heat rate 

improvement is not subject to major 

NSR requirements, it will often require 

a minor NSR permit from its permitting 

agency. As noted in Section VIII.A of 

this preamble, the minor NSR program 

applies to new and modified sources 

that are not subject to major NSR 

permitting. The purpose of a minor NSR 

program is, along with major NSR, to 

ensure that sources of air emissions are 

properly regulated so that the NAAQS 

are attained and protected. For example, 

under EPA’s tribal minor NSR program, 

the reviewing authority (i.e., EPA or a 

delegated Tribe) must ensure that the 

NAAQS are protected through the 

permitting process. The reviewing 

authority has the option to require an air 

quality impact analysis for individual 

permits if they deem it necessary based 

on air quality concerns.66 All minor 

NSR permits require a public notice 

process and the permit may potentially 

require the installation of air pollution 

controls based on an assessment by the 

permitting authority. 

Furthermore, states use measures 

contained in their State Implementation 

Plan (SIP) to ensure that local air quality 

impacts are addressed or minimized to 

the extent possible. A SIP may include 

(1) state-adopted control measures 

which consist of either regulations or 

source-specific requirements (e.g., 

orders and consent decrees); (2) statesubmitted ‘‘non-regulatory’’ components 

(e.g., maintenance plans and attainment 

demonstrations); and (3) additional 

requirements promulgated by EPA to 

satisfy a mandatory requirement in 

Section 110 or Part D of the CAA. 

Supplementing the Agency’s legal and 

policy rationale provided in the 2007 

SNPRM, EPA is taking comment on an 

important factor that EPA believes 

supports for moving forward with the 

addition of an NSR hourly emissions 

test for EGUs: EPA is now proposing a 

rule that could result in sources being 

required to perform HRIs (as determined 

by their state 111(d) plans) rather than 

sources independently deciding to do 

them (Comment C–66). EPA believes 

this added factor of the 111(d) GHG 

emission guidelines for EGUs directing 

sources to consider HRIs when 

complying with their state plans may 

make the case for adopting an NSR 

hourly emissions test for EGUs more 

compelling. EPA requests comment on 

the extent to which EPA should allow 

the adoption of an NSR hourly 

emissions test for EGUs in light of EPA’s 

decision to issue these proposed 

emission guidelines for the power sector 

(Comment C–67). 

EPA is also taking comment on other 

ways to minimize or eliminate any 

adverse impact that NSR may have on 

implementing section 111(d) plans for 

EGUs (Comment C–68). Specifically, 

have there been court decisions since 

New York I and New York II that can be 

read to afford EPA more flexibility with 

respect to its reading of the definition of 

‘‘modification’’ in the context of the 

NSR program? 

For example, when EPA undertook 

the challenge of applying the PSD 

program to GHGs, the Supreme Court 

pointed to several instances where EPA 

had permissibly narrowed the scope of 

the general CAA definition of ‘‘air 

pollutant’’ based on the surrounding 

context of provisions within which the 

term is used, including the NSR 

program. UARG v. EPA, 134 S.Ct. 2427, 

2439–41 (2014). Based in part on this 

observation, the Court rejected EPA’s 

strict interpretation that the term ‘‘air 

pollutant’’ must apply to greenhouse 

gases in the context of the definition of 

‘‘major emitting facility’’ in section 

169(1) of the Act in spite of the 

Agency’s recognition that such a reading 

would dramatically expand the reach of 

the PSD program to smaller scale 

construction that Congress had never 

intended to cover. Id. at 2442. In a like 

manner, does EPA have more flexibility 

with regard to its interpretation of the 

definition of ‘‘modification’’ in the 

context of the PSD program than the 

D.C. Circuit has previously recognized? 

Where the D.C. Circuit’s reading of the 

definition of ‘‘modification’’ in the PSD 

context would produce results that 

frustrates Congressional objectives in 

the CAA section 111 programs, does the 

reasoning of the Supreme Court in 

UARG supply a basis for EPA to develop 

a narrower form of a pollution control 

project exclusion from NSR? 

The requirements of the CAA section 

111 program were intended to work in 

harmony with NSR and other provisions 

of the Act. The complementary 

relationship of the programs is evident 

from the statutory requirements. Both 

programs are intended to protect air 

quality from stationary sources of 

pollution, and they rely on many of the 

same CAA provisions and definitions— 

namely, the programs’ framework for 

existing sources are both rooted in the 

same definition for ‘‘modification.’’ In 

addition, there are instances in which 

the CAA cross links the programs such 

that a requirement from one program 

bears an influence on the other program. 

For example, in accordance with CAA 

section 169(3), an applicable standard of 

performance under NSPS establishes the 

minimum level of stringency for BACT 

for a source getting a PSD permit. 

Similarly, LAER must reflect an 

emission rate that is does not exceed the 

allowable emission rate under any 

applicable NSPS. CAA section 171(3). 

Thus, the NSPS program sets the 

minimum performance standards for 

new stationary sources as part of 

program to ensure air quality is 

protected, and NSR authorizes the 

construction or modification of sources 

of air pollution, taking into account the 

NSPS as it examines what the source 

needs to do to control its emissions in 

order to adequately protect or improve 

air quality. 

Thus, EPA believes the two programs 

are intended to complement—not 

conflict with—each other. However, 

because changes considered under 

111(d) plans could result in a source 

triggering NSR under the current NSR 

rules and increasing the costs to the 

point that undertaking HRI are less 

financially feasible for some sources, 

can EPA apply the reasoning of UARG 

to read the definition of ‘‘modification’’ 

in this context to afford more flexibility 

to exempt sources from NSR 

requirements when they are compelled 

to make changes by an NSPS (Comment 

C–69)? 

5. State Adoption 

As the hourly emissions test for NSR 

would be one tool for implementing the 

ACE rule, EPA expects that some states 

may determine that they do not need or 

desire to change the NSR applicability 

requirements for EGUs. Consequently, 

EPA does not intend the NSR hourly 

emissions test to be a mandatory 

element of state programs (as EPA had 

proposed in 2007). EPA is proposing for 

this action that states would have the 

discretion to decide whether to 

incorporate the NSR hourly emissions 

test for EGUs into their rules. However, 

state and local permitting authorities 

that are issuing permits on behalf of 

EPA under a delegation agreement will 

be required to apply the NSR hourly 

emissions test for EGUs, since they 

would follow the Federal NSR program 

provided in 40 CFR part 52 (which 

would be amended to include section 


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52.25). EPA solicits comment on 

allowing states this flexibility to adopt 

the proposed NSR rule changes and on 

any other considerations with respect to 

state (or local/district agency) adoption 

and implementation of the proposed 

NSR changes (Comment C–70). 

6. Severability 

Although EPA proposes to finalize 

these NSR revisions as part of an 

integrated action with the rest of this 

proposal, EPA views the revisions to the 

definition of BSER, revisions to the 

implementing regulations, and emission 

guideline proposed in this proposal as 

appropriate policies in their own right 

and on their own terms. EPA intends 

that the NSR revisions, if finalized, 

would be severable from the other 

provisions on judicial review. EPA 

solicits comment on whether it would 

be appropriate to finalize the NSR 

revisions as a separate action from the 

remainder of the proposal (Comment C– 

71). 

7. Submitting Comments 

Please submit all comments on this 

NSR section docket established for this 

rulemaking (Docket ID number EPA– 

HQ–OAR–2017–0355). To the extent 

that you previously commented on the 

October 20, 2005 NPRM and/or May 8, 

2007 SNPRM and desire for your 

comments to be considered for this 

proposed action, please resubmit them. 

IX. Impacts 

A. What are the air impacts? 

In the Regulatory Impact Analysis 

(RIA) for this proposed rulemaking, the 

Agency provides a full benefit cost 

analysis of four illustrative scenarios. 

The four illustrative scenarios include a 

scenario modeling the full repeal of the 

CPP (which can also be conceptualized 

as the legal state of affairs as of the date 

of this proposal, given the Supreme 

Court stay of the CPP) and three policy 

scenarios modeling heat rate 

improvements (HRI) at coal-fired EGUs. 

Throughout the RIA, these three 

illustrative policy scenarios are 

compared against a base case, which 

includes the CPP. By analyzing against 

the CPP, the reader can understand the 

combined impact of the CPP repeal and 

proposed ACE rule. Inclusion of a no 

CPP case allows for an understanding of 

the repeal alone and also allows the 

reader to evaluate the impact of the 

policy cases against a no CPP scenario. 

The RIA assumes a mass-based 

implementation of the CPP for existing 

affected sources, and does not assume 

interstate trading. The three illustrative 

policy scenarios represent potential 

outcomes of state determinations of 

standards of performance, and 

compliance with those standards by 

affected coal-fired EGUs. These policy 

scenarios illustrate the analysis of the 

world without the CPP, the world with 

this proposal, and the difference in the 

effects of this proposal and those of the 

CPP. 

The illustrative policy scenarios 

model different levels and costs of HRIs 

applied uniformly at all affected coalfired EGUs in the contiguous U.S. 

beginning in 2025. EPA has identified 

the BSER to be HRI. Each of these 

illustrative scenarios assumes that the 

affected sources are no longer subject to 

the state plan requirements of the CPP 

(i.e., the mass-based requirements 

assumed for CPP implementation in the 

base case for the RIA). The cost, 

suitability, and potential improvement 

for any of these HRI technologies is 

dependent on a range of unit-specific 

factors such as the size, age, fuel use, 

and the operating and maintenance 

history of the unit. As such, the HRI 

potential can vary significantly from 

unit to unit. EPA does not have 

sufficient information to assess HRI 

potential on a unit-by-unit basis. To 

avoid the impression that EPA can 

sufficiently distinguish likely standards 

of performance across individual 

affected units and their compliance 

strategies, this analysis assumes 

different HRI levels and costs are 

applied uniformly to affected coal-fired 

EGUs under each of three illustrative 

policy scenarios: 

The first illustrative scenario, 2 

Percent HRI at $50/kW, represents a 

policy case that reflects modest 

improvements in HRI absent any 

revisions to NSR requirements. For 

many years, industry has indicated to 

the Agency that many sources have not 

implemented certain HRI projects 

because the burdensome costs of NSR 

cause such projects to not be viable. 

Thus, absent NSR reform, HRI at 

affected units might be expected to be 

modest. Based on numerous studies and 

statistical analysis, the Agency believes 

that the HRI potential for coal-fired 

EGUs will, on average, range from one 

to three percent at a cost of $30 to $60 

per kilowatt (kW) of EGU generating 

capacity. The Agency believes that this 

scenario (2 percent HRI at $50/kW) 

reasonably represents that range of HRI 

and cost. 

The second illustrative scenario, 4.5 

Percent HRI at $50/kW, represents a 

policy case that includes benefits from 

the proposed revisions to NSR, with the 

HRI modeled at a low cost. As 

mentioned earlier, the Agency is 

proposing revisions to the NSR program 

that will provide owners and operators 

of existing EGUs greater ability to make 

efficiency improvements without 

triggering the provisions of NSR. This 

scenario is informative in that it 

represents the ability of all coal-fired 

EGUs to obtain greater improvements in 

heat rate because of NSR reform at the 

$50/kW cost identified earlier. EPA 

believes this higher heat rate 

improvement potential is possible 

because without NSR a greater number 

of units may have the opportunity to 

make cost effective heat rate 

improvements such as steam turbine 

upgrades that have the potential to offer 

greater heat rate improvement 

opportunities. 

The third illustrative scenario, 4.5 

Percent HRI at $100/kW, represents a 

policy case that includes the benefits 

from the proposed revisions to NSR, 

with the HRI modeled at a higher cost. 

This scenario is informative in that it 

represents the ability of a typical coalfired EGU to obtain greater 

improvements in heat rate because of 

NSR reform but at a much higher cost 

($100/kW) than the $50/kW cost 

identified earlier. Particularly for lower 

capacity units or those with limited 

remaining useful life, this could 

ultimately translate into HRI projects 

with costs beyond what most states 

might determine to be reasonable. 

Combined, the 4.5 percent HRI at $50/ 

kW scenario and the 4.5 percent HRI at 

$100/kW scenario represent a range of 

potential costs for the proposed policy 

option that couples HRI with NSR 

reform. Modeling this at $50/kW and 

$100/kW provides a sensitivity analysis 

on the cost of the proposed policy 

including NSR reform. The $50/kW cost 

represents an optimistic bounding 

where NSR reform unleashes significant 

new opportunity for low-cost heat rate 

improvements. The $100/kW cost 

scenario, while informative, represents a 

high-end bound that could overstate 

potential because, particularly for lower 

capacity factor units and those with 

limited remaining useful life, these 

would represent project costs that states 

would likely find to be unreasonable. 

The Agency understands that there 

may be interest in comparing the three 

illustrative policy scenarios against an 

alternative baseline that does not 

include the CPP. For those interested in 

comparing the potential impacts of the 

policy scenarios in a world without the 

CPP, results from the three illustrative 

policy scenarios may be compared 

against an alternative baseline results 

from the illustrative No CPP scenario. 

The presentation of an alternative 

baseline is consistent with Circular A– 

4, which states, ‘‘When more than one 


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44784 Federal Register / Vol. 83, No. 170 / Friday, August 31, 2018 / Proposed Rules 

67Office of Management and Budget (OMB), 2003, 

Circular A–4, https://www.whitehouse.gov/sites/ 

whitehouse.gov/files/omb/circulars/A4/a-4.pdf. 

baseline is reasonable and the choice of 

baseline will significantly affect 

estimated benefits and costs, you should 

consider measuring benefits and costs 

against alternative baselines’’ 67 In 

addition, the full suite of model outputs 

and additional comparisons tables are 

available in the rulemaking docket. 

EPA evaluates the potential regulatory 

impacts of the illustrative No CPP 

scenario and the three illustrative policy 

scenarios using the present value (PV) of 

costs, benefits, and net benefits, 

calculated for the years 2023–2037 from 

the perspective of 2016, using both a 

three percent and seven percent 

beginning-of-period discount rate. In 

addition, the Agency presents the 

assessment of costs, benefits, and net 

benefits for specific snapshot years, 

consistent with historic practice. In the 

RIA, the regulatory impacts are 

evaluated for the specific years of 2025, 

2030, and 2035. 

Emissions are projected to be higher 

under the three illustrative policy 

scenarios and the illustrative No CPP 

scenario than under the base case, as the 

base case includes the CPP. Table 6 

shows projected emission increases 

relative to the base case for CO2, SO2

and NOX from the electricity sector. 

Table 7 shows the same emissions 

change information, except relative to 

the No CPP alternative baseline. 

TABLE 6—PROJECTED CO2, SO2, AND NOX ELECTRICITY SECTOR EMISSION INCREASES, RELATIVE TO THE BASE CASE

(CPP) (2025–2035) 

CO2

(million 

short tons) 

SO2

(thousand 

short tons) 

NOX

(thousand 

short tons) 

No CPP 

2025 ............................................................................................................................................. 50 36 32 

2030 ............................................................................................................................................. 74 60 47 

2035 ............................................................................................................................................. 66 44 43 

2% HRI at $50/kW 

2025 ............................................................................................................................................. 37 35 24 

2030 ............................................................................................................................................. 61 53 39 

2035 ............................................................................................................................................. 55 34 39 

4.5% HRI at $50/kW 

2025 ............................................................................................................................................. 32 40 21 

2030 ............................................................................................................................................. 60 53 39 

2035 ............................................................................................................................................. 59 43 43 

4.5% HRI at $100/kW 

2025 ............................................................................................................................................. 20 32 14 

2030 ............................................................................................................................................. 47 45 32 

2035 ............................................................................................................................................. 44 29 33 

TABLE 7—PROJECTED CO2, SO2, AND NOX ELECTRICITY SECTOR EMISSION CHANGES, RELATIVE TO THE NO CPP 

ALTERNATIVE BASELINE

[2025–2035] 

CO2

(million 

short tons) 

SO2

(thousand 

short tons) 

NOX

(thousand 

short tons) 

Base Case (CPP) 

2025 ............................................................................................................................................. ¥50 ¥36 ¥32 

2030 ............................................................................................................................................. ¥74 ¥60 ¥47 

2035 ............................................................................................................................................. ¥66 ¥44 ¥43 

2% HRI at $50/kW 

2025 ............................................................................................................................................. ¥13 0 ¥8 

2030 ............................................................................................................................................. ¥13 ¥7 ¥8 

2035 ............................................................................................................................................. ¥11 ¥11 ¥5 

4.5% HRI at $50/kW 

2025 ............................................................................................................................................. ¥18 4 ¥11 

2030 ............................................................................................................................................. ¥14 ¥7 ¥8 

2035 ............................................................................................................................................. ¥7 ¥1 ¥1 


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TABLE 7—PROJECTED CO2, SO2, AND NOX ELECTRICITY SECTOR EMISSION CHANGES, RELATIVE TO THE NO CPP 

ALTERNATIVE BASELINE—Continued 

[2025–2035] 

CO2

(million 

short tons) 

SO2

(thousand 

short tons) 

NOX

(thousand 

short tons) 

4.5% HRI at $100/kW 

2025 ............................................................................................................................................. ¥30 ¥3 ¥18 

2030 ............................................................................................................................................. ¥27 ¥15 ¥15 

2035 ............................................................................................................................................. ¥22 ¥16 ¥11 

The emissions changes in these tables 

do not account for changes in hazardous 

air pollutants (HAPs) that may occur as 

a result of this rule. For projected 

impacts on mercury emissions, please 

see Chapter 3 of the RIA for this 

proposed rulemaking. 

B. What are the energy impacts? 

The proposed actions have energy 

market implications. Overall, the 

analysis to support this proposed rule 

indicates that there are important power 

sector impacts that are worth noting, 

although they are relatively small 

compared to other EPA air regulatory 

actions for EGUs. The estimated impacts 

reflect EPA’s illustrative analysis of the 

proposed rule, which applies various 

levels of heat rate improvements to 

affected sources in order to ascertain 

how they might respond, in order to 

capture the potential systemwide 

economic and energy impacts of the 

requirements. States are afforded 

considerable flexibility in this proposed 

rule, and thus the impacts could be 

different, to the extent states make 

different choices. 

Table 8 presents a variety of energy 

market impacts for 2025, 2030, and 2035 

for the four illustrative scenarios, 

relative to the base case, which includes 

the CPP. 

TABLE 8—SUMMARY OF CERTAIN ENERGY MARKET IMPACTS, RELATIVE TO BASE CASE (CPP) 

[Percent change] 

2025 

(%) 

2030 

(%) 

2035 

(%) 

No CPP 

Retail electricity prices ................................................................................................................. ¥0.5 ¥0.4 ¥0.1 

Average price of coal delivered to the power sector .................................................................. ¥0.1 ¥0.2 ¥0.4 

Coal production for power sector use ......................................................................................... 6.1 9.2 9.5 

Price of natural gas delivered to power sector ........................................................................... ¥1.1 ¥0.3 0.1 

Price of average Henry Hub (spot) ............................................................................................. ¥1.4 ¥0.8 ¥0.2 

Natural gas use for electricity generation .................................................................................... ¥1.5 ¥1.5 ¥0.9 

2% HRI at $50/kW 

Retail electricity prices ................................................................................................................. ¥0.3 ¥0.2 ¥0.1 

Average price of coal delivered to the power sector .................................................................. 0.2 ¥0.1 ¥0.4 

Coal production for power sector use ......................................................................................... 5.5 8.0 8.4 

Price of natural gas delivered to power sector ........................................................................... ¥1.1 ¥0.9 ¥0.4 

Price of average Henry Hub (spot) ............................................................................................. ¥1.4 ¥1.3 ¥0.6 

Natural gas use for electricity generation .................................................................................... ¥2.5 ¥1.7 ¥1.1 

4.5% HRI at $50/kW 

Retail electricity prices ................................................................................................................. ¥0.5 ¥0.4 ¥0.2 

Average price of coal delivered to the power sector .................................................................. 0.7 0.6 0.3 

Coal production for power sector use ......................................................................................... 5.8 8.6 9.5 

Price of natural gas delivered to power sector ........................................................................... ¥1.4 ¥1.1 ¥0.7 

Price of average Henry Hub (spot) ............................................................................................. ¥1.7 ¥1.6 ¥1.0 

Natural gas use for electricity generation .................................................................................... ¥3.4 ¥2.5 ¥1.9 

4.5% HRI at $100/kW 

Retail electricity prices ................................................................................................................. ¥0.2 0.0 0.0 

Average price of coal delivered to the power sector .................................................................. 0.5 0.3 ¥0.1 

Coal production for power sector use ......................................................................................... 4.5 7.1 7.4 

Price of natural gas delivered to power sector ........................................................................... ¥1.3 ¥1.1 ¥0.7 

Price of average Henry Hub (spot) ............................................................................................. ¥1.6 ¥1.6 ¥1.0 

Natural gas use for electricity generation .................................................................................... ¥3.4 ¥2.3 ¥1.6 


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44786 Federal Register / Vol. 83, No. 170 / Friday, August 31, 2018 / Proposed Rules 

Energy market impacts are discussed 

more extensively in the RIA found in 

the rulemaking docket. 

C. What are the compliance costs? 

The power industry’s ‘‘compliance 

costs’’ are represented in this analysis as 

the change in electric power generation 

costs between the base case and 

illustrative scenarios, including the cost 

of monitoring, reporting, and 

recordkeeping (MR&R). In simple terms, 

these costs are an estimate of the 

increased power industry expenditures 

required to implement the HRI required 

by the proposed rule, minus the sectoral 

cost of complying with the CPP 

assumed in the base case. 

The compliance assumptions—and, 

therefore, the projected compliance 

costs—set forth in this analysis are 

illustrative in nature and do not 

represent the plans that states may 

ultimately pursue. The illustrative 

compliance scenarios are designed to 

reflect, to the extent possible, the scope 

and nature of the proposed guidelines. 

However, there is considerable 

uncertainty with regards to the precise 

measure that states will adopt to meet 

the proposed requirements, because 

there are considerable flexibilities 

afforded to the states in developing their 

state plans. 

Table 9 presents the annualized 

compliance costs of the three illustrative 

policy scenarios and the illustrative No 

CPP scenario. In this table, and 

throughout the RIA for this proposed 

rulemaking, negative costs indicate 

avoided costs relative to the base case 

(which includes the CPP), and positive 

costs indicate an increase in projected 

compliance costs, relative to the base 

case. As shown in Table 9, the Agency 

estimates that there are avoided costs 

under three out of the four illustrative 

scenarios. Table 7 shows the same 

compliance cost information, except 

relative to the No CPP alternative 

baseline. 

TABLE 9—COMPLIANCE COSTS, RELATIVE TO BASE CASE (CPP) 

[Billions of 2016$] 

CPP repeal 2% HRI 

at $50/kW 

4.5% HRI 

at $50/kW 

4.5% HRI 

at $100/kW 

2025 ................................................................................................................. (0.7) 0.0 (0.6) 0.5 

2030 ................................................................................................................. (0.7) (0.2) (1.0) 0.2 

2035 ................................................................................................................. (0.4) 0.1 (0.6) 0.5 

Notes: Negative costs indicate that, on net, the illustrative scenario avoids costs relative to the base case with the CPP. Compliance costs 

equal the projected change in total power sector generating costs, plus the costs of monitoring, reporting, and recordkeeping. 

TABLE 10—COMPLIANCE COSTS, RELATIVE TO THE NO CPP ALTERNATIVE BASELINE

[Billions of 2016$] 

2% HRI 

at $50/kW 

4.5% HRI 

at $50/kW 

4.5% HRI 

at $100/kW 

2025 ............................................................................................................................................. 0.7 0.1 1.3 

2030 ............................................................................................................................................. 0.5 (0.2) 0.9 

2035 ............................................................................................................................................. 0.5 (0.2) 0.8 

Notes: Negative costs indicate that, on net, the illustrative scenario reduces costs relative to the No CPP alternative baseline. Compliance 

costs equal the projected change in total power sector generating costs, plus the costs of monitoring, reporting, and recordkeeping. 

Due to a number of changes in the 

electricity sector since the CPP was 

finalized, as documented in the October 

2017 RIA conducted for the proposed 

CPP repeal and Chapter 3 of the RIA for 

this action, the sector has become less 

carbon intensive over the past several 

years, and the trend is projected to 

continue. These changes and trends are 

reflected in the modeling used for this 

analysis. As such, achieving the 

emissions levels required under CPP 

requires less effort and expense, relative 

to a scenario without the CPP, and the 

estimated compliance costs are 

significantly lower than what was 

estimated in the final CPP RIA. More 

detailed cost estimates are available in 

the RIA included in the rulemaking 

docket. 

D. What are the economic and 

employment impacts? 

Environmental regulation may affect 

groups of workers differently, as 

changes in abatement and other 

compliance activities cause labor and 

other resources to shift. An employment 

impact analysis describes the 

characteristics of groups of workers 

potentially affected by a regulation, as 

well as labor market conditions in 

affected occupations, industries, and 

geographic areas. Market and 

employment impacts of this proposed 

action are discussed more extensively in 

Chapter 5 of the RIA for this proposed 

rulemaking. 

E. What are the benefits of the proposed 

action? 

EPA reports the impact on climate 

benefits from changes in CO2 and the 

impact on health benefits attributable to 

changes in SO2, NOX and PM2.5

emissions. EPA refers to the climate 

benefits as ‘‘targeted pollutant benefits’’ 

as they reflect the direct benefits of 

reducing CO2, and to the ancillary 

health benefits as ‘‘co-benefits’’ as they 

are not benefits from reducing the 

targeted pollutant. To estimate the 

climate benefits associated with changes 

in CO2 emissions, EPA applies a 

measure of the domestic social cost of 

carbon (SC–CO2). The SC–CO2 is a 

metric that estimates the monetary value 

of impacts associated with marginal 

changes in CO2 emissions in a given 

year. The SC–CO2 estimates used in the 

RIA for this proposed rulemaking focus 

on the direct impacts of climate change 

that are anticipated to occur within U.S. 

borders. 

The estimated health co-benefits are 

the monetized value of the forgone 

human health benefits among 

populations exposed to changes in PM2.5

and ozone. This rule is expected to alter 

the emissions of SO2 and NOX

emissions, which will in turn affect the 

level of PM2.5 and ozone in the 

atmosphere. Using photochemical 

modeling, EPA predicted the change in 

the annual average PM2.5 and summer 


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Federal Register / Vol. 83, No. 170 / Friday, August 31, 2018 / Proposed Rules 44787 

season ozone across the U.S. for the 

years 2025, 2030 and 2035. EPA next 

quantified the human health impacts 

and economic value of these changes in 

air quality using the environmental 

Benefits Mapping and Analysis 

Program—Community Edition. EPA 

quantified effects using concentrationresponse parameters detailed in the RIA 

and that are consistent with those 

employed by the Agency in the PM 

NAAQS and Ozone NAAQS RIAs (U.S. 

EPA, 2012; 2015). In these tables, 

negative values represent forgone 

benefits and positive benefits represent 

realized benefits. 


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Table 11. Forgone Benefits: Estimated Economic Value of Incremental PM2.5 and OzoneAttributable Deaths and Illnesses for Illustrative Scenarios & Three Alternative 

Approaches to Representing PM Effects in 2025, Relative to Base Case (CPP) (95% 

Confidence Interval; Billions of 2016$t 

NoCPP 2% HRI at $50/kW 4.5% HRiat 

$50/kW 

4.5%HRI at 

$100/kW 

Ozone benefits summed with PM~~l!!!~:·~<<<~ <<<~<<~<~~~<<<,~,,~,~ <~, 

-$2.8 -$2.6 -$5.9 Nothreshold 

modelE 

(-$0.3 (-$0.3 to (-$0.5 

~- ~-

Effects 

above 

LMLC 

Effects 

above 

NAAQSD 

to-

-$0.12 

(-$0 to 

-$0.4) 

to 

to 

-$2.4 

( -$0.1 

to -$7) 

-$0.4 

(-$0 to 

-$1.3) 

Ozone benefits summed with PM benefits: 

Nothreshold 

modelE 

Effects 

above 

LMLC 

Effects 

above 

NAAQSD 

-$2.6 

(-$0.3 

to -$7) 

-$1.7 

(-$0 to 

-$5) 

-$0.12 

(-$0 to 

1 

to (-$0.6 

to 

to 

A Values rOlmded to two significant figures 

to $7) $17) 

-$1.5 

( -$0.1 

to -$4) 

-$0.06 

(-$0 to 

-$0.2) 

-$2.4 

(-$0.2 

to 

to 

to 

-$1.4 

(-$0.1 to 

to -$4) 

-$0.06 

(-$0 to to 

-$0.2) 

-$2.2 

(-$0.2 

to -$6) 

-$0.21 

(-$0 to 

-$0.6) 

-$2 

(-$0.2 

to -$5) 

-$0.21 

($0 to 

-$0.6) 

to -

$7.4) 

-$1.6 

($0.2 

to -

$4.6) 

-$0.04 

($0 to 

-$0.1) 

( -$0.1 

to -

$4.2) 

-$0.04 

($0 to 

-$0.1) 

to 

to 

to 

to-

$18) 

-$2.3 

(-$0.2 

to -$6) 

-$0.12 

(-$0 to 

-$0.4) 

-$2.1 

to (-$0.2 

to -$6) 

-$0.12 

to (-$0 to 

-$0.4) 

to-

$5.9) 

-$1.1 

($.1 to 

-$3.3) 

$0.07 

($0.2 

to $0) 

-$0.99 

($0.1 

to -$3) 

$0.07 

($0.2 

to $0) 

to 

to 

to 

to 

to 

to 

B PM effects quantified using a no-threshold model. Low end of range reflects dollar value of effects quantified using 

concentration-response parameter from Krewski et al. (2009) and Smith et al. (2008) studies; upper end quantified using 

parameters from Lepeule et al. (2012) and Jerrett et al. (2009). 

to -

$14) 

-$1.8 

( -$0.1 

to -$5) 

-$0.02 

( -$0.1 

to $0) 

-$4.4 

(-$0.2 

$0.02 

($0.1 

to $0) 

c PM effects quantified at or above the Lowest Measured Level of each long-term epidemiological study. Low end of range 

reflects dollar value of effects quantified down to LML of Lepeule et al. (20 12) study (8 ~g/m ); high end of range reflects dollar 

value of effects quantified down to LML ofKrewski et al. (2009) study (5.8 ~g/m ). 

D PM effects only quantified at or above the annual mean of 12 to provide insight regarding the fraction of benefits occurring 

above the NAAQS. Range reflects effects quantified using concentration-response parameters from Smith et al. (2008) study at 

the low end and Jerrett et al. (2009) at the high end. 
44788 Federal Register / Vol. 83, No. 170 / Friday, August 31, 2018 / Proposed Rules 


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Table 12. Forgone Benefits: Estimated Economic Value of Incremental PM2.5 and OzoneAttributable Deaths and Illnesses for Illustrative Scenarios & Three Alternative 

Approaches to Representing PM Effects in 2030, Relative to Base Case (CPP) (95% 

Confidence Interval; Billions of 2016$t 

NoCPP 2% HRI at $50/kW 4.5%HRI at 

$50/kW 

Ozone benefits summed with PM benefits: 

Nothreshold 

modelE 

Effects 

above 

LMLC 

;::;::::00 

cr. Effects 

above 

NAAQSD 

-$4.9 

(-$0.47 

to -$13) 

-$3.5 

( -$0.33 

to -$10) 

-$0.26 

to 

to 

($0 to- to 

$0.75) 

-$11 

( -$1 to 

-$33) 

-$4.2 

( -$0.4 

,......................... -~··································~~~ 

-$4.5 

(-$0.4 

toto 

-$11 

( -$1 

to -

( -$0.4 

to -

Ozone benefits summed with PM benefits: 

Nothreshold 

modelE 

Effects 

above 

LMLC 

Effects 

above 

NAAQSD 

-$4.5 -$10 , .......... _ ... $·:··4·:···.-·1·:·······································_···$·:···9·:·· .·8·:··· ··---$ ::3:.9 :··········· 

(-$0.43 to (-$1 to (-$0.4 to (-$0. 9 (-$0.4 

to - to - to - to -$12) -$30) $11) $~ ) $11) 

-$3.3 -$3.8 -$3.5 -$3.5 -$3.3 

(-$0.3 to (-$0.4 (-$0.3 to (-$0.3 (-

to - to - to - to - $0.32 

_____::$:c:..9:.cc.4)'-----:::..::$1:..::..0)~. $?:7) __ _!!_Q2~. to -$9) 

-$0.43 -$1.5 

-$0.26 -$0.92 ( -$.04 to ( -$O.l -$0.18 

($0 to - to ( -$0.1 ($0 to 

$0.8) to -$3) to - to - -$0.5) 

A Values rOlmded to two significant figures 

to 

to 

to 

to 

to 

to 

-$9.8 

( -$0.9 

toto-

( -$0.1 

to -

-$9 

(-$0.8 

to-

-$0.63 

(-$0.1 

to -$2) 

4.5%HRI at 

$100/kW 

-$3.6 

(-$0.34 

toto-

-$3.3 

(-$0.3 

to-

-$0.13 

(-$0 to 

-$0.4) 

to 

to 

-$8.2 

( -$0.8 

to -

$24) 

-$3 

( -$0.3 

to -$8) 

-$0.46 

to ($0 to 

-$1.4) 

to 

to 

to 

-$7.6 

(-$0.7 

to -

$22) 

-$2.8 

( -$0.3 

to -$8) 

-$0.46 

(-$0 to 

-$1.4) 

B PM effects quantified using a no-threshold model. Low end of range reflects dollar value of effects quantified using 

concentration-response parameter from Krewski et al. (2009) and Smith et al. (2008) studies; upper end quantified using 

parameters from Lepeule et al. (2012) and Jerrett et al. (2009). 

c PM effects quantified at or above the Lowest Measured Level of each long-term epidemiological study. Low end of range 

reflects dollar value of effects quantified down to LML of Lepeule et al. (20 12) study (8 11g/m3

); high end of range reflects dollar 

value of effects quantified down to LML ofKrewski et al. (2009) study (5.8 11g/m3

). 

D PM effects only quantified at or above the annual mean of 12 to provide insight regarding the fraction of benefits occurring 

above the NAAQS. Range reflects effects quantified using concentration-response parameters from Smith et al. (2008) study at 

the low end and Jerrett et al. (2009) at the high end. 
Federal Register / Vol. 83, No. 170 / Friday, August 31, 2018 / Proposed Rules 44789 

Table 14 reports the combined 

domestic climate benefits and ancillary 

health co-benefits attributable to 

changes in SO2 and NOX emissions 

estimated for 3 percent and 7 percent 

discount rates in the years 2025, 2030 

and 2035, in 2016 dollars. This table 

reports the air pollution effects 

calculated using PM2.5 log-linear no 

threshold concentration-response 

functions that quantify risk associated 

with the full range of PM2.5 exposures 

experienced by the population (U.S. 

EPA, 2009; U.S. EPA, 2011; NRC, 2002). 

In this table, negative benefits 

indicate forgone benefits, relative to the 

base case, which includes the CPP. As 

all benefit estimates in this table are 

negative values, this indicates that the 

Agency estimates there to be forgone 

climate benefits and forgone ancillary 

health co-benefits under all four 

illustrative scenarios in the years and 

discount rates analyzed relative to the 

base case. 


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44790 Federal Register / Vol. 83, No. 170 / Friday, August 31, 2018 / Proposed Rules 

68The Federal Register notice for the 2012 PM 

NAAQS indicates that ‘‘[i]n considering this 

additional population level information, the 

Administrator recognizes that, in general, the 

confidence in the magnitude and significance of an 

association identified in a study is strongest at and 

around the long-term mean concentration for the air 

quality distribution, as this represents the part of 

the distribution in which the data in any given 

study are generally most concentrated. She also 

recognizes that the degree of confidence decreases 

as one moves towards the lower part of the 

distribution.’’ 

TABLE 14—MONETIZED BENEFITS, RELATIVE TO BASE CASE (CPP) 

[billions of 2016$] 

Values calculated using 3% discount rate Values calculated using 7% discount rate 

Domestic 

climate 

benefits 

Ancillary 

health 

co-benefits 

Total 

benefits 

Domestic 

climate 

benefits 

Ancillary 

health 

co-benefits 

Total 

benefits 

No CPP 

2025 ....................... (0.3) (2.8) to (6.6) ........... (3.2) to (7.0) ........... (0.1) (2.6) to (6.1) ........... (2.7) to (6.1) 

2030 ....................... (0.5) (4.9) to (11.4) ......... (5.4) to (11.9) ......... (0.1) (4.5) to (10.5) ......... (4.6) to (10.6) 

2035 ....................... (0.5) (3.8) to (8.8) ........... (4.3) to (9.3) ........... (0.1) (3.5) to (8.1) ........... (3.6) to (8.2) 

2% HRI at $50/kW 

2025 ....................... (0.2) (2.6) to (5.9) ........... (2.8) to (6.2) ........... (0.0) (2.4) to (5.4) ........... (2.4) to (5.5) 

2030 ....................... (0.4) (4.5) to (10.6) ......... (4.9) to (11.0) ......... (0.1) (4.1) to (9.8) ........... (4.2) to (9.9) 

2035 ....................... (0.4) (3.0) to (7.0) ........... (3.4) to (7.4) ........... (0.1) (2.7) to (6.5) ........... (2.8) to (6.6) 

4.5% HRI at $50/kW 

2025 ....................... (0.2) (2.7) to (6.2) ........... (2.9) to (6.4) ........... (0.0) (2.5) to (5.7) ........... (2.5) to (5.7) 

2030 ....................... (0.4) (4.2) to (9.8) ........... (4.6) to (10.2) ......... (0.1) (3.9) to (9.0) ........... (3.9) to (9.1)

2035 ....................... (0.5) (4.0) to (9.3) ........... (4.4) to (9.8) ........... (0.1) (3.7) to (8.6) ........... (3.7) to (8.7) 

4.5% HRI at $100/kW 

2025 ....................... (0.1) (2.1) to (4.9) ........... (2.3) to (5.0) ........... (0.0) (2.0) to (4.4) ........... (2.0) to (4.4) 

2030 ....................... (0.3) (3.6) to (8.2) ........... (3.9) to (8.6) ........... (0.1) (3.3) to (7.6) ........... (3.3) to (7.6) 

2035 ....................... (0.3) (2.6) to (6.0) ........... (2.9) to (6.3) ........... (0.1) (2.4) to (5.5) ........... (2.4) to (5.6) 

Notes: Negative benefit values indicate forgone benefits relative to the base case, which includes the CPP. All estimates are rounded to one 

decimal point, so figures may not sum due to independent rounding. Climate benefits reflect the value of domestic impacts from CO2 emissions 

changes. The ancillary health co-benefits reflect the sum of the PM2.5 and ozone benefits from changes in electricity sector SO2, NOX, and PM2.5

emissions and reflect the range based on adult mortality functions (e.g., from Krewski et al. (2009) with Smith et al. (2009) to Lepeule et al. 

(2012) with Jerrett et al. (2009)) using a log-linear no threshold model. 

In general, EPA is more confident in 

the size of the risks estimated from 

simulated PM2.5 concentrations that 

coincide with the bulk of the observed 

PM concentrations in the 

epidemiological studies that are used to 

estimate the benefits. Likewise, EPA is 

less confident in the risk EPA estimates 

from simulated PM2.5 concentrations 

that fall below the bulk of the observed 

data in these studies.68 Furthermore, 

when setting the 2012 PM NAAQS, the 

Administrator also acknowledged 

greater uncertainty in specifying the 

‘‘magnitude and significance’’ of PMrelated health risks at PM 

concentrations below the NAAQS. As 

noted in the preamble to the 2012 PM 

NAAQS final rule, ‘‘EPA concludes that 

it is not appropriate to place as much 

confidence in the magnitude and 

significance of the associations over the 

lower percentiles of the distribution in 

each study as at and around the longterm mean concentration.’’ (78 FR 3154, 

January 15, 2013). In general, we are 

more confident in the size of the risks 

we estimate from simulated PM2.5

concentrations that coincide with the 

bulk of the observed PM concentrations 

in the epidemiological studies that are 

used to estimate the benefits. Likewise, 

we are less confident in the risk we 

estimate from simulated PM2.5

concentrations that fall below the bulk 

of the observed data in these studies. 

To give readers insight to the 

distribution of estimated forgone 

benefits displayed in Table 14, EPA also 

reports the PM benefits according to 

alternative concentration cut-points and 

concentration-response parameters. The 

percentage of estimated PM2.5-related 

deaths occurring below the lowest 

measured levels (LML) of the two longterm epidemiological studies EPA uses 

to estimate risk varies between 16 

percent (Krewski et al. 2009) and 79 

percent (Lepeule et al. 2012). The 

percentage of estimated premature 

deaths occurring above the LML and 

below the NAAQS ranges between 84 

percent (Krewski et al. 2009) and 21 

percent (Lepeule et al. 2012). Less than 

1% of the estimated premature deaths 

occur above the annual mean PM2.5

NAAQS of 12 mg/m3. 

Monetized co-benefits estimates 

shown here do not include several 

important benefit categories, such as 

direct exposure to SO2, NOX and 

hazardous air pollutants including 

mercury and hydrogen chloride. 

Although EPA does not have sufficient 

information or modeling available to 

provide monetized estimates of changes 

in exposure to these pollutants for this 

rule, EPA includes a qualitative 

assessment of these unquantified 

benefits in the RIA. For more 

information on the benefits analysis, 

please refer to the RIA for this rule, 

which is available in the rulemaking 

docket. 

X. Statutory and Executive Order 

Reviews 

Additional information about these 

Statutory and Executive Orders can be 

found at https://www.epa.gov/lawsregulations/laws-and-executive-orders. 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

This proposed action is an 

economically significant action that was 


daltland on DSKBBV9HB2PROD with PROPOSALS2
Federal Register / Vol. 83, No. 170 / Friday, August 31, 2018 / Proposed Rules 44791 

submitted to the OMB for review. Any 

changes made in response to OMB 

recommendations have been 

documented in the docket. EPA 

prepared an analysis of the compliance 

cost, benefit, and net benefit impacts 

associated with this action in the 

analysis years of 2025, 2030, and 2035. 

This analysis, which is contained in the 

Regulatory Impact Analysis (RIA) for 

this proposed rulemaking, is consistent 

with Executive Order 12866 and is 

available in the rulemaking docket. 

In the RIA for this proposed 

rulemaking, the Agency presents full 

benefit cost analysis of four illustrative 

scenarios. The four illustrative scenarios 

include a scenario modeling the full 

repeal of the CPP and three policy 

scenarios modeling heat rate 

improvements (HRI) at coal-fired EGUs. 

Throughout the RIA, these three 

illustrative policy scenarios are 

compared against a base case, which 

includes the CPP. By analyzing against 

the CPP, the reader can understand the 

combined impact of a CPP repeal and 

proposed ACE rule. Inclusion of a No 

CPP case allows for an understanding of 

the repeal alone and also allows the 

reader to evaluate the impact of the 

policy cases against a No CPP scenario. 

The RIA assumes a mass-based 

implementation of the CPP for existing 

affected sources, and does not assume 

interstate trading. The three illustrative 

policy scenarios represent potential 

outcomes of state determinations of 

standards of performance, and 

compliance with those standards by 

affected coal-fired EGUs. 

The Agency understands that there 

may be interest in comparing the three 

illustrative policy scenarios against a 

scenario that does not include the CPP. 

For those interested in comparing the 

potential impacts of policy scenarios in 

a world without the CPP, results from 

the three illustrative policy scenarios 

may be compared against results from 

the illustrative No CPP scenario. We 

provide information here on compliance 

costs, emissions impacts and present 

value net benefits compared to the No 

CPP alternative baseline. In addition, 

the Executive Summary and Chapter 3 

of the RIA compares the three 

illustrative policy scenarios to the 

scenario of a full CPP repeal. Also, the 

full suite of model outputs is available 

in the rulemaking docket. 

The three illustrative policy scenarios 

model different levels and costs of HRIs 

applied uniformly at all affected coalfired EGUs in the contiguous U.S. 

beginning in 2025. EPA has identified 

the BSER to be HRI. Each of these 

illustrative scenarios assumes that the 

affected sources are no longer subject to 

the state plan requirements of the CPP 

(i.e., the mass-based requirements 

assumed for CPP implementation in the 

base case for the RIA). The cost, 

suitability, and potential improvement 

for any of these HRI technologies is 

dependent on a range of unit-specific 

factors such as the size, age, fuel use, 

and the operating and maintenance 

history of the unit. As such, the HRI 

potential can vary significantly from 

unit to unit. EPA does not have 

sufficient information to assess HRI 

potential on a unit-by-unit basis. 

To avoid the impression that EPA can 

sufficiently distinguish likely standards 

of performance across individual 

affected units and their compliance 

strategies, this analysis assumes 

different HRI levels and costs are 

applied uniformly to affected coal-fired 

EGUs under each of three illustrative 

policy scenarios. 

The first illustrative scenario, 2 

Percent HRI at $50/kW, represents a 

policy case that reflects modest 

improvements in HRI absent any 

revisions to NSR requirements. For 

many years, industry has indicated to 

the Agency that many sources have not 

implemented certain HRI projects 

because the burdensome costs of NSR 

cause such projects to not be viable. 

Thus, absent NSR reform, HRI at 

affected units might be expected to be 

modest. Based on numerous studies and 

statistical analysis, the Agency believes 

that the HRI potential for coal-fired 

EGUs will, on average, range from one 

to three percent at a cost of $30 to $60 

per kilowatt (kW) of EGU generating 

capacity. The Agency believes that this 

scenario (2 percent HRI at $50/kW) 

reasonably represents that range of HRI 

and cost. 

The second illustrative scenario, 4.5 

Percent HRI at $50/kW, represents a 

policy case that includes benefits from 

the proposed revisions to NSR, with the 

HRI modeled at a low cost. As 

mentioned earlier, the Agency is 

proposing revisions to the NSR program 

that will provide owners and operators 

of existing EGUs greater ability to make 

efficiency improvements without 

triggering provisions of NSR. This 

scenario is informative in that it 

represents the ability of all coal-fired 

EGUs to obtain greater improvements in 

heat rate because of NSR reform at the 

$50/kW cost identified earlier. EPA 

believes this higher heat rate 

improvement potential is possible 

because without NSR a greater number 

of units may have the opportunity to 

make cost effective heat rate 

improvements such as turbine upgrades 

that have the potential to offer greater 

heat rate improvement opportunities. 

The third illustrative scenario, 4.5 

Percent HRI at $100/kW, represents a 

policy case that includes the benefits 

from the proposed revisions to NSR, 

with the HRI modeled at a higher cost. 

This scenario is informative in that it 

represents the ability of a typical coalfired EGUs to obtain greater 

improvements in heat rate because of 

NSR reform but at a much higher cost 

($100/kW) than the $50/kW cost 

identified earlier. Particularly for lower 

capacity units or those with limited 

remaining useful life, this could 

ultimately translate into HRI projects 

with costs beyond what most states 

might determine to be reasonable. 

Combined, the 4.5 percent HRI at $50/ 

kW scenario and the 4.5 percent HRI at 

$100/kW scenario represent a range of 

potential costs for the proposed policy 

option that couples HRI with NSR 

reform. Modeling this at $50/kW and 

$100/kW provides a sensitivity analysis 

on the cost of the proposed policy 

including NSR reform. The $50/kW cost 

represents an optimistic bounding 

where NSR reform unleashes significant 

new opportunity for low-cost heat rate 

improvements. The $100/kW cost 

scenario, while informative, represents a 

high-end bound that could overstate 

potential because, particularly for lower 

capacity factor units and those with 

limited remaining useful life, these 

would represent project costs that states 

would likely find to be unreasonable. 

We evaluate the potential regulatory 

impacts of the illustrative No CPP 

scenario and the three illustrative policy 

scenarios using the present value (PV) of 

costs, benefits, and net benefits, 

calculated for the years 2023–2037 from 

the perspective of 2016, using both a 

three percent and seven percent 

beginning-of-period discount rate. In 

addition, the Agency presents the 

assessment of costs, benefits, and net 

benefits for specific snapshot years, 

consistent with historic practice. In the 

RIA, the regulatory impacts are 

evaluated for the specific years of 2025, 

2030, and 2035. 

The power industry’s ‘‘compliance 

costs’’ are represented in this analysis as 

the change in electric power generation 

costs between the base case and 

illustrative scenarios, including the cost 

of monitoring, reporting, and 

recordkeeping (MR&R). In simple terms, 

these costs are an estimate of the 

increased power industry expenditures 

required to implement the HRI required 

by the proposed rule, minus the sectoral 

cost of complying with the CPP 

assumed in the base case. 

The compliance assumptions—and, 

therefore, the projected compliance 

costs—set forth in this analysis are 


daltland on DSKBBV9HB2PROD with PROPOSALS2
44792 Federal Register / Vol. 83, No. 170 / Friday, August 31, 2018 / Proposed Rules 

69The Federal Register notice for the 2012 PM 

NAAQS indicates that ‘‘[i]n considering this 

additional population level information, the 

Administrator recognizes that, in general, the 

confidence in the magnitude and significance of an 

association identified in a study is strongest at and 

around the long-term mean concentration for the air 

quality distribution, as this represents the part of 

the distribution in which the data in any given 

study are generally most concentrated. She also 

recognizes that the degree of confidence decreases 

as one moves towards the lower part of the 

distribution.’’ 

illustrative in nature and do not 

represent the plans that states may 

ultimately pursue. The illustrative 

compliance scenarios are designed to 

reflect, to the extent possible, the scope 

and nature of the proposed guidelines. 

However, there is considerable 

uncertainty with regards to the precise 

measure that states will adopt to meet 

the proposed requirements, because 

there are considerable flexibilities 

afforded to the states in developing their 

state plans. 

EPA reports the impact on climate 

benefits from changes in CO2 and the 

impact on health benefits attributable to 

changes in SO2, NOX and PM2.5

emissions. We refer to the climate 

benefits as ‘‘targeted pollutant benefits’’ 

as they reflect the direct benefits of 

reducing CO2, and to the ancillary 

health benefits as ‘‘co-benefits’’ as they 

are not benefits from reducing the 

targeted pollutant. To estimate the 

climate benefits associated with changes 

in CO2 emissions, we apply a measure 

of the domestic social cost of carbon 

(SC-CO2). The SC-CO2 is a metric that 

estimates the monetary value of impacts 

associated with marginal changes in 

CO2 emissions in a given year. The SCCO2 estimates used in the RIA for this 

proposed rulemaking focus on the direct 

impacts of climate change that are 

anticipated to occur within U.S. 

borders. 

The health co-benefits estimates 

represent the monetized value of the 

forgone human health benefits among 

populations exposed to changes in PM2.5

and ozone. This rule is expected to alter 

the emissions of SO2, NOX, and PM2.5

emissions, which will in turn affect the 

level of PM2.5 and ozone in the 

atmosphere. Using photochemical 

modeling, we predicted the change in 

the annual average PM2.5 and summer 

season ozone across the U.S. for the 

years 2025, 2030 and 2035. We next 

quantified the human health impacts 

and economic value of these changes in 

air quality using the environmental 

Benefits Mapping and Analysis 

Program—Community Edition. We 

quantified effects using concentrationresponse parameters detailed in the RIA 

and that are consistent with those 

employed by the Agency in the PM 

NAAQS and Ozone NAAQS RIAs (U.S. 

EPA, 2012; 2015). 

In general, we are more confident in 

the size of the risks we estimate from 

simulated PM2.5 concentrations that 

coincide with the bulk of the observed 

PM concentrations in the 

epidemiological studies that are used to 

estimate the benefits. Likewise, we are 

less confident in the risk we estimate 

from simulated PM2.5 concentrations 

that fall below the bulk of the observed 

data in these studies.69

Furthermore, when setting the 2012 

PM NAAQS, the Administrator also 

acknowledged greater uncertainty in 

specifying the ‘‘magnitude and 

significance’’ of PM-related health risks 

at PM concentrations below the 

NAAQS. As noted in the preamble to 

the 2012 PM NAAQS final rule, ‘‘EPA 

concludes that it is not appropriate to 

place as much confidence in the 

magnitude and significance of the 

associations over the lower percentiles 

of the distribution in each study as at 

and around the long-term mean 

concentration.’’ (78 FR 3154, 15 January 

2013). In general, we are more confident 

in the size of the risks we estimate from 

simulated PM2.5 concentrations that 

coincide with the bulk of the observed 

PM concentrations in the 

epidemiological studies that are used to 

estimate the benefits. Likewise, we are 

less confident in the risk we estimate 

from simulated PM2.5 concentrations 

that fall below the bulk of the observed 

data in these studies. 

To give readers insight to the 

distribution of estimated forgone 

benefits displayed in Table 14, EPA also 

reports the PM benefits according to 

alternative concentration cut-points and 

concentration-response parameters. To 

give readers insight to the uncertainty in 

the estimated forgone PM2.5 mortality 

benefits occurring at lower ambient 

levels, we also report the PM benefits 

according to alternative concentration 

cut-points and concentration-response 

parameters. The percentage of estimated 

PM2.5-related deaths occurring below 

the lowest measured levels (LML) of the 

two long-term epidemiological studies 

we use to estimate risk varies between 

16 percent (Krewski et al. 2009) and 79 

percent (Lepeule et al. 2012). The 

percentage of estimated premature 

deaths occurring above the LML and 

below the NAAQS ranges between 84 

percent (Krewski et al. 2009) and 21 

percent (Lepeule et al. 2012). Less than 

1% of the estimated premature deaths 

occur above the annual mean PM2.5

NAAQS of 12 mg/m3. 

Monetized co-benefits estimates 

shown here do not include several 

important benefit categories, such as 

direct exposure to SO2, NOX and 

hazardous air pollutants including 

mercury and hydrogen chloride. 

Although we do not have sufficient 

information or modeling available to 

provide monetized estimates of changes 

in exposure to these pollutants for this 

rule, we include a qualitative 

assessment of these unquantified 

benefits in the RIA. For more 

information on the benefits analysis, 

please refer to the RIA for this rule, 

which is available in the rulemaking 

docket. 

In the decision-making process it is 

useful to consider the change in benefits 

due to the targeted pollutant relative to 

the costs. Therefore, in Chapter 6 of the 

RIA for this proposed rulemaking we 

present a comparison of the benefits 

from the targeted pollutant—CO2—with 

the compliance costs. Excluded from 

this comparison are the benefits from 

changes in PM2.5 and ozone 

concentrations from changes in SO2, 

NOX and PM2.5 emissions that are 

projected to accompany changes in CO2

emissions. 

Table 15 presents the present value 

(PV) and equivalent annualized value 

(EAV) of the estimated costs, benefits, 

and net benefits associated with the 

targeted pollutant, CO2, for the 

timeframe of 2023–2037, relative to the 

base case, which includes the CPP. The 

EAV represents an even-flow of figures 

over the timeframe of 2023–2037 that 

would yield an equivalent present 

value. The EAV is identical for each 

year of the analysis, in contrast to the 

year-specific estimates presented earlier 

for the snapshot years of 2025, 2030, 

and 2035. 

In Table 15, and all net benefit tables, 

negative costs indicate avoided costs, 

negative benefits indicate forgone 

benefits, and negative net benefits 

indicate forgone net benefits. 


daltland on DSKBBV9HB2PROD with PROPOSALS2
Federal Register / Vol. 83, No. 170 / Friday, August 31, 2018 / Proposed Rules 44793 

TABLE 15—PRESENT VALUE AND EQUIVALENT ANNUALIZED VALUE OF COMPLIANCE COSTS, CLIMATE BENEFITS, AND NET

BENEFITS ASSOCIATED WITH TARGETED POLLUTANT (CO2), RELATIVE TO BASE CASE (CPP), 3 AND 7 PERCENT DISCOUNT RATES, 2023–2037 

[Billions of 2016$] 

Costs Domestic 

climate benefits 

Net benefits 

associated with the 

targeted pollutant 

(CO2) 3% 7% 3% 7% 

3% 7% 

Present Value 

No CPP ........................................................................... (5.2) (3.1) (3.9) (0.4) 1.2 2.7 

2% HRI at $50/kW .......................................................... (0.4) (0.3) (3.2) (0.3) (2.8) (0.1) 

4.5% HRI at $50/kW ....................................................... (6.4) (3.7) (3.2) (0.3) 3.2 3.4 

4.5% HRI at $100/kW ..................................................... 3.0 1.7 (2.4) (0.2) (5.4) (2.0) 

Equivalent Annualized Value 

No CPP ........................................................................... (0.4) (0.3) (0.3) (0.0) 0.1 0.3 

2% HRI at $50/kW .......................................................... (0.0) (0.0) (0.3) (0.0) (0.2) (0.0) 

4.5% HRI at $50/kW ....................................................... (0.5) (0.4) (0.3) (0.0) 0.3 0.4 

4.5% HRI at $100/kW ..................................................... 0.3 0.2 (0.2) (0.0) (0.5) (0.2) 

Notes: Negative costs indicate avoided costs, negative benefits indicate forgone benefits, and negative net benefits indicate forgone net benefits. All estimates are rounded to one decimal point, so figures may not sum due to independent rounding. Climate benefits reflect the value of 

domestic impacts from CO2 emissions changes. This table does not include estimates of ancillary health co-benefits from changes in electricity 

sector SO2 and NOX emissions. 

Table 16 presents the costs, benefits, 

and net benefits associated with the 

targeted pollutant for specific years, 

rather than as a PV or EAV as found in 

Table 18. 

TABLE 16—COMPLIANCE COSTS, CLIMATE BENEFITS, AND NET BENEFITS ASSOCIATED WITH TARGETED POLLUTANT

(CO2), RELATIVE TO BASE CASE (CPP), 3 AND 7 PERCENT DISCOUNT RATES, 2025, 2030, AND 2035 

[Billions of 2016$] 

Costs Domestic 

climate benefits 

Net benefits 

associated with the 

targeted pollutant 

(CO2) 3% 7% 3% 7% 

3% 7% 

No CPP 

2025 ................................................................................ (0.7) (0.7) (0.3) (0.1) 0.4 0.7 

2030 ................................................................................ (0.7) (0.7) (0.5) (0.1) 0.2 0.6 

2035 ................................................................................ (0.4) (0.4) (0.5) (0.1) (0.1) 0.3 

2% HRI at $50/kW 

2025 ................................................................................ 0.0 0.0 (0.2) (0.0) (0.3) (0.1) 

2030 ................................................................................ (0.2) (0.2) (0.4) (0.1) (0.2) 0.2 

2035 ................................................................................ 0.1 0.1 (0.4) (0.1) (0.6) (0.2) 

4.5% HRI at $50/kW 

2025 ................................................................................ (0.6) (0.6) (0.2) (0.0) 0.4 0.6 

2030 ................................................................................ (1.0) (1.0) (0.4) (0.1) 0.5 0.9 

2035 ................................................................................ (0.6) (0.6) (0.5) (0.1) 0.2 0.5 

4.5% HRI at $100/kW 

2025 ................................................................................ 0.5 0.5 (0.1) (0.0) (0.7) (0.5) 

2030 ................................................................................ 0.2 0.2 (0.3) (0.1) (0.5) (0.2) 

2035 ................................................................................ 0.5 0.5 (0.3) (0.1) (0.8) (0.5) 

Notes: Negative costs indicate avoided costs, negative benefits indicate forgone benefits, and negative net benefits indicate forgone net benefits. All estimates are rounded to one decimal point, so figures may not sum due to independent rounding. Climate benefits reflect the value of 

domestic impacts from CO2 emissions changes. This table does not include estimates of ancillary health co-benefits from changes in electricity 

sector SO2 and NOX emissions. 


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Table 17 presents the present value (PV) 

and equivalent annualized value (EAV) 

of the estimated costs, benefits, and net 

benefits associated with the targeted 

pollutant, CO2, for the timeframe of 

2023–2037, relative to the No CPP 

alternative baseline. 

TABLE 17—PRESENT VALUE AND EQUIVALENT ANNUALIZED VALUE OF COMPLIANCE COSTS, CLIMATE BENEFITS, AND NET

BENEFITS ASSOCIATED WITH TARGETED POLLUTANT (CO2), RELATIVE TO THE NO CPP ALTERNATIVE BASELINE, 3 

AND 7 PERCENT DISCOUNT RATES, 2023–2037 

[Billions of 2016$] 

Costs Domestic 

climate benefits 

Net benefits 

associated with the 

targeted pollutant 

(CO2) 3% 7% 3% 7% 

3% 7% 

Present Value 

2% HRI at $50/kW .......................................................... 4.8 2.8 0.8 0.1 (4.1) (2.8) 

4.5% HRI at $50/kW ....................................................... (1.2) (0.6) 0.7 0.1 2.0 0.7 

4.5% HRI at $100/kW ..................................................... 8.2 4.8 1.6 0.2 (6.6) (4.7) 

Equivalent Annualized Value 

2% HRI at $50/kW .......................................................... 0.4 0.3 0.1 0.0 (0.3) (0.3) 

4.5% HRI at $50/kW ....................................................... (0.1) (0.1) 0.1 0.0 0.2 0.1 

4.5% HRI at $100/kW ..................................................... 0.7 0.5 0.1 0.0 (0.6) (0.5) 

Notes: Negative costs indicate avoided costs, negative benefits indicate forgone benefits, and negative net benefits indicate forgone net benefits. All estimates are rounded to one decimal point, so figures may not sum due to independent rounding. Climate benefits reflect the value of 

domestic impacts from CO2 emissions changes. This table does not include estimates of ancillary health co-benefits from changes in electricity 

sector SO2 and NOX emissions. 

Table 18 and Table 19 provide the 

estimated costs, benefits, and net 

benefits, inclusive of the ancillary 

health-co benefits and relative to the 

base case (CPP). Table 18 presents the 

PV and EAV estimates, and Table 19 

presents the estimates for the specific 

years of 2025, 2030, and 2035. 

TABLE 18—PRESENT VALUE AND EQUIVALENT ANNUALIZED VALUE OF COMPLIANCE COSTS, TOTAL BENEFITS, AND NET

BENEFITS, RELATIVE TO BASE CASE (CPP), 3 AND 7 PERCENT DISCOUNT RATES, 2023–2037 

[Billions of 2016$] 

Costs Benefits Net benefits 

3% 7% 3% 7% 3% 7% 

Present Value 

No CPP ......................... (5.2) (3.1) (37.2) to (81.5) ....... (17.9) to (41.3) ....... (32.0) to (76.3) ....... (14.8) to (38.2) 

2% HRI at $50/kW ........ (0.4) (0.3) (32.7) to (72.4) ....... (15.9) to (36.9) ....... (32.3) to (72.0) ....... (15.7) to (36.7) 

4.5% HRI at $50/kW ..... (6.4) (3.7) (34.3) to (75.2) ....... (16.6) to (39.4) ....... (27.9) to (68.8) ....... (12.8) to (35.6) 

4.5% HRI at $100/kW ... 3.0 1.7 (27.2) to (60.2) ....... (13.9) to (31.9) ....... (30.2) to (63.2) ....... (15.6) to (33.7) 

Equivalent Annualized Value 

No CPP ......................... (0.4) (0.3) (3.1) to (6.8) ........... (2.0) to (4.5) ........... (2.7) to (6.4) ........... (1.6) to (4.2) 

2% HRI at $50/kW ........ (0.0) (0.0) (2.7) to (6.1) ........... (1.7) to (4.1) ........... (2.7) to (6.0) ........... (1.7) to (4.0) 

4.5% HRI at $50/kW ..... (0.5) (0.4) (2.9) to (6.3) ........... (1.8) to (4.3) ........... (2.3) to (5.8) ........... (1.4) to (3.9) 

4.5% HRI at $100/kW ... 0.3 0.2 (2.3) to (5.0) ........... (1.5) to (3.5) ........... (2.5) to (5.3) ........... (1.7) to (3.7) 

Notes: Negative costs indicate avoided costs, negative benefits indicate forgone benefits, and negative net benefits indicate forgone net benefits. All estimates are rounded to one decimal point, so figures may not sum due to independent rounding. Total benefits include both climate 

benefits and ancillary health co-benefits. Climate benefits reflect the value of domestic impacts from CO2 emissions changes. The ancillary 

health co-benefits reflect the sum of the PM2.5 and ozone benefits from changes in electricity sector SO2, NOX and PM2.5 emissions and reflect 

the range based on adult mortality functions (e.g., from Krewski et al. (2009) with Smith et al. (2009) to Lepeule et al. (2012) with Jerrett et al. 

(2009)). PM premature mortality benefits estimated using a log-linear no-threshold model. 


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TABLE 19—COMPLIANCE COSTS, TOTAL BENEFITS, AND NET BENEFITS, RELATIVE TO BASE CASE (CPP), 3 AND 7 

PERCENT DISCOUNT RATES, 2025, 2030, AND 2035 

[Billions of 2016$] 

Costs Benefits Net benefits 

3% 7% 3% 7% 3% 7% 

No CPP 

2025 .............................. (0.7) (0.7) (3.2) to (7.0) ........... (2.7) to (6.1) ........... (2.4) to (6.2) ........... (1.9) to (5.4) 

2030 .............................. (0.7) (0.7) (5.4) to (11.9) ......... (4.6) to (10.6) ......... (4.7) to (11.2) ......... (3.8) to (9.8) 

2035 .............................. (0.4) (0.4) (4.3) to (9.3) ........... (3.6) to (8.2) ........... (3.9) to (8.9) ........... (3.2) to (7.8) 

2% HRI at $50/kW 

2025 .............................. 0.0 0.0 (2.8) to (6.2) ........... (2.4) to (5.5) ........... (2.8) to (6.2) ........... (2.4) to (5.5) 

2030 .............................. (0.2) (0.2) (4.9) to (11.0) ......... (4.2) to (9.9) ........... (4.7) to (10.8) ......... (3.9) to (9.7) 

2035 .............................. 0.1 0.1 (3.4) to (7.4) ........... (2.8) to (6.6) ........... (3.5) to (7.6) ........... (3.0) to (6.7) 

4.5% HRI at $50/kW 

2025 .............................. (0.6) (0.6) (2.9) to (6.4) ........... (2.5) to (5.7) ........... (2.3) to (5.8) ........... (1.9) to (5.1) 

2030 .............................. (1.0) (1.0) (4.6) to (10.2) ......... (3.9) to (9.1) ........... (3.7) to (9.2) ........... (3.0) to (8.1) 

2035 .............................. (0.6) (0.6) (4.4) to (9.8) ........... (3.7) to (8.7) ........... (3.8) to (9.2) ........... (3.1) to (8.1) 

4.5% HRI at $100/kW 

2025 .............................. 0.5 0.5 (2.3) to (5.0) ........... (2.0) to (4.4) ........... (2.8) to (5.5) ........... (2.5) to (5.0) 

2030 .............................. 0.2 0.2 (3.9) to (8.6) ........... (3.3) to (7.6) ........... (4.1) to (8.7) ........... (3.5) to (7.8) 

2035 .............................. 0.5 0.5 (2.9) to (6.3) ........... (2.4) to (5.6) ........... (3.4) to (6.8) ........... (2.9) to (6.0) 

Notes: Negative costs indicate avoided costs, negative benefits indicate forgone benefits, and negative net benefits indicate forgone net benefits. All estimates are rounded to one decimal point, so figures may not sum due to independent rounding. Total benefits include both climate 

benefits and ancillary health co-benefits. Climate benefits reflect the value of domestic impacts from CO2 emissions changes. The ancillary 

health co-benefits reflect the sum of the PM2.5 and ozone benefits from changes in electricity sector SO2, NOX and PM2.5 emissions and reflect 

the range based on adult mortality functions (e.g., from Krewski et al. (2009) with Smith et al. (2009) to Lepeule et al. (2012) with Zanobetti & 

Schwartz. (2008)). PM premature mortality benefits estimated using a log-linear no-threshold model. 

Table 20 provides the estimated costs, 

benefits, and net benefits, inclusive of 

the ancillary health-co benefits and 

relative to the No CPP alternative 

baseline. 

TABLE 20—PRESENT VALUE AND EQUIVALENT ANNUALIZED VALUE OF COMPLIANCE COSTS, TOTAL BENEFITS, AND NET

BENEFITS, RELATIVE TO THE NO CPP ALTERNATIVE BASELINE, 3 AND 7 PERCENT DISCOUNT RATES, 2023–2037 

[Billions of 2016$] 

Costs Benefits Net benefits 

3% 7% 3% 7% 3% 7% 

Present Value 

2% HRI at $50/kW ........ 4.8 2.8 4.5 to 9.2 ............... 2.0 to 4.3 ............... (0.3) to 4.3 ............. (0.9) to 1.5 

4.5% HRI at $50/kW ..... (1.2) (0.6) 2.9 to 6.3 ............... 1.4 to 1.9 ............... 4.1 to 7.5 ............... 2.0 to 2.6 

4.5% HRI at $100/kW ... 8.2 4.8 10.0 to 21.3 ........... 4.1 to 9.4 ............... 1.8 to 13.2 ............. (0.8) to 4.5 

Equivalent Annualized Value 

2% HRI at $50/kW ........ 0.4 0.3 0.4 to 0.8 ............... 0.2 to 0.5 ............... (0.0) to 0.4 ............. (0.1) to 0.2 

4.5% HRI at $50/kW ..... (0.1) (0.1) 0.2 to 0.5 ............... 0.1 to 0.2 ............... 0.3 to 0.6 ............... 0.2 to 0.3 

4.5% HRI at $100/kW ... 0.7 0.5 0.8 to 1.8 ............... 0.4 to 1.0 ............... 0.1 to 1.1 ............... (0.1) to 0.5 

Notes: Negative costs indicate avoided costs, negative benefits indicate forgone benefits, and negative net benefits indicate forgone net benefits. All estimates are rounded to one decimal point, so figures may not sum due to independent rounding. Total benefits include both climate 

benefits and ancillary health co-benefits. Climate benefits reflect the value of domestic impacts from CO2 emissions changes. The ancillary 

health co-benefits reflect the sum of the PM2.5 and ozone benefits from changes in electricity sector SO2, NOX and PM2.5 emissions and reflect 

the range based on adult mortality functions (e.g., from Krewski et al. (2009) with Smith et al. (2009) to Lepeule et al. (2012) with Jerrett et al. 

(2009)). PM premature mortality benefits estimated using a log-linear no-threshold model. 

Throughout the RIA for this proposed 

rulemaking, EPA examines a number of 

sources of uncertainty, both 

quantitatively and qualitatively, on 

benefits and costs. Some of these 

elements are evaluated using 

probabilistic techniques. For other 

elements, where the underlying 

likelihoods of certain outcomes are 

unknown, we use scenario analysis to 

evaluate their potential effect on the 

benefits and costs of this proposed 


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rulemaking. We summarize key 

elements of our analysis of uncertainty 

here: 

• The extent to which all coal-fired 

EGUs will improve heat rates under this 

proposal, on average; 

• The cost to improve heat rates at all 

affected coal-fired EGUs nationally; 

• Uncertainty in monetizing climaterelated benefits; and, 

• Uncertainty in the estimated health 

impacts attributable to changes in 

particulate matter. 

In the RIA for this proposed 

rulemaking, EPA also summarize other 

potential sources of benefits and costs 

that may result from this proposed rule 

that have not been quantified or 

monetized. 

B. Executive Order 13771: Reducing 

Regulation and Controlling Regulatory 

Costs 

This action is expected to be an 

Executive Order 13771 deregulatory 

action. Details on the estimated cost 

savings of this proposed rule can be 

found in the rule’s RIA. 

C. Paperwork Reduction Act (PRA) 

The information collection activities 

in this proposed rule have been 

submitted for approval to the Office of 

Management and Budget (OMB) under 

the PRA. The Information Collection 

Request (ICR) document that EPA 

prepared has been assigned EPA ICR 

number 2503.03. You can find a copy of 

the ICR in the docket for this rule, and 

it is briefly summarized here. 

The information collection 

requirements are based on the 

recordkeeping and reporting burden 

associated with developing, 

implementing, and enforcing a state 

plan to limit CO2 emissions from 

existing sources in the power sector. 

These recordkeeping and reporting 

requirements are specifically authorized 

by CAA section 114 (42 U.S.C. 7414). 

All information submitted to EPA 

pursuant to the recordkeeping and 

reporting requirements for which a 

claim of confidentiality is made is 

safeguarded according to Agency 

policies set forth in 40 CFR part 2, 

subpart Ba. 

Respondents/affected entities: 48. 

Respondent’s obligation to respond: 

EPA expects state plan submissions 

from the 43 contiguous states and 

negative declarations from Vermont, 

California, Maine, Idaho, and Rhode 

Island. 

Frequency of response: Yearly. 

Total estimated burden: 192,640 

hours (per year). Burden is defined at 5 

CFR 1320.3(b). 

Total estimated cost: $21,500 

annualized capital or operation & 

maintenance costs. 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to, a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for EPA’s regulations in 40 

CFR are listed in 40 CFR part 9. 

Submit your comments on the 

Agency’s need for this information, the 

accuracy of the provided burden 

estimates and any suggested methods 

for minimizing respondent burden to 

EPA using the docket identified at the 

beginning of this rule (Comment C–72). 

You may also send your ICR-related 

comments to OMB’s Office of 

Information and Regulatory Affairs via 

email to OIRA_submission@

omb.eop.gov, Attention: Desk Officer for 

EPA. Since OMB is required to make a 

decision concerning the ICR between 30 

and 60 days after receipt, OMB must 

receive comments no later than October 

1, 2018. EPA will respond to any ICRrelated comments in the final rule. 

D. Regulatory Flexibility Act (RFA) 

After considering the economic 

impacts of this proposed rule on small 

entities, I certify that this action will not 

have a significant economic impact on 

a substantial number of small entities. 

The proposed rule will not impose any 

requirements on small entities. 

Specifically, emission guidelines 

established under CAA section 111(d) 

do not impose any requirements on 

regulated entities and, thus, will not 

have a significant economic impact 

upon a substantial number of small 

entities. After emission guidelines are 

promulgated, states establish emission 

standards on existing sources, and it is 

those state requirements that could 

potentially impact small entities. Our 

analysis in the accompanying RIA is 

consistent with the analysis of the 

analogous situation arising when EPA 

establishes NAAQS, which do not 

impose any requirements on regulated 

entities. As with the description in the 

RIA, any impact of a NAAQS on small 

entities would only arise when states 

take subsequent action to maintain and/ 

or achieve the NAAQS through their 

state implementation plans. See 

American Trucking Assoc. v. EPA, 175 

F.3d 1029, 1043–45 (D.C. Cir. 1999) 

(NAAQS do not have significant 

impacts upon small entities because 

NAAQS themselves impose no 

regulations upon small entities). 

Nevertheless, EPA is aware that there 

is substantial interest in the proposed 

rule among small entities (municipal 

and rural electric cooperatives) and we 

invite comments on all aspects of the 

proposal and its impacts, including 

potential impacts on small entities 

(Comment C–73). 

E. Unfunded Mandates Reform Act 

(UMRA) 

This action does not contain a federal 

mandate that may result in expenditures 

of $100 million or more for state, local 

and tribal governments, in the aggregate 

or the private sector in any one year. 

Specifically, the emission guidelines 

proposed under CAA section 111(d) do 

not impose any direct compliance 

requirements on regulated entities, apart 

from the requirement for states to 

develop state plans. The burden for 

states to develop state plans in the 

three-year period following 

promulgation of the rule was estimated 

and is listed in Section IX.C above, but 

this burden is estimated to be below 

$100 million in any one year. Thus, this 

proposed rule is not subject to the 

requirements of section 203 or section 

205 of the Unfunded Mandates Reform 

Act (UMRA). 

This proposed rule is also not subject 

to the requirements of section 203 of 

UMRA because, as described in 2 U.S.C. 

1531–38, it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. This 

action imposes no enforceable duty on 

any state, local, or tribal governments or 

the private sector. 

F. Executive Order 13132: Federalism 

Under Executive Order 13132, EPA 

may not issue an action that has 

federalism implications, that imposes 

substantial direct compliance costs and 

that is not required by statute unless the 

federal government provides the funds 

necessary to pay the direct compliance 

costs incurred by state and local 

governments, or EPA consults with state 

and local officials early in the process 

of developing the proposed action. 

EPA has concluded that this action 

may have federalism implications 

because it might impose substantial 

direct compliance costs on state or local 

governments, and the federal 

government will not provide the funds 

necessary to pay those costs. The 

development of state plans will entail 

many hours of staff time to develop and 

coordinate programs for compliance 

with the proposed rule, as well as time 

to work with state legislatures as 

appropriate, and develop a plan 

submittal. 

In the spirit of Executive Order 13132, 

and consistent with EPA’s policy to 

promote communications between EPA 

and state and local governments, EPA 

specifically solicits comment on this 


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70See Chapter 5, ‘‘Economic and Employment 

Impacts’’, of the RIA. 

71See Chapter 5, ‘‘Economic and Employment 

Impacts,’’ of the RIA. 

proposed action from state and local 

officials (Comment C–74). 

G. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have tribal 

implications as specified in Executive 

Order 13175. It would not impose 

substantial direct compliance costs on 

tribal governments that have affected 

EGUs located in their area of Indian 

country. Tribes are not required to 

develop plans to implement the 

guidelines under CAA section 111(d) for 

affected EGUs. EPA notes that this 

proposal does not directly impose 

specific requirements on EGU sources, 

including those located in Indian 

country, but before developing any 

standards for sources on tribal land, 

EPA would consult with leaders from 

affected tribes. This proposed action 

also will not have substantial direct 

effects on the relationship between the 

federal government and Indian tribes or 

on the distribution of power and 

responsibilities between the federal 

government and Indian tribes, as 

specified in Executive Order 13175. 

Thus, Executive Order 13175 does not 

apply to the action. 

Consistent with EPA Policy on 

Consultation and Coordination with 

Indian Tribes, EPA will engage in 

consultation with tribal officials during 

the development of this action. 

H. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

This proposed action is subject to 

Executive Order 13045 because it is an 

economically significant regulatory 

action as defined by Executive Order 

12866. The CPP, as discussed in the 

RIA,70 was anticipated to reduce 

emissions of PM2.5 and ozone, and some 

of the benefits of reducing these 

pollutants would have accrued to 

children. While the proposed ACE rule 

does not project to achieve reductions at 

the level of the CPP, EPA believes that 

this proposal will achieve CO2 emission 

reductions resulting from 

implementation of these proposed 

guidelines, as well as ozone and PM2.5

emission reductions as a co-benefit, and 

will further improve children’s health as 

discussed in the RIA. 

Moreover, this proposed action does 

not affect the level of public health and 

environmental protection already being 

provided by existing NAAQS, including 

ozone and PM2.5, and other mechanisms 

in the CAA. This proposed action does 

not affect applicable local, state, or 

federal permitting or air quality 

management programs that will 

continue to address areas with degraded 

air quality and maintain the air quality 

in areas meeting current standards. 

Areas that need to reduce criteria air 

pollution to meet the NAAQS will still 

need to rely on control strategies to 

reduce emissions. 

I. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This proposed action, which is a 

significant regulatory energy action 

under Executive Order 12866, is likely 

to have a significant effect on the 

supply, distribution, or use of energy. 

Specifically, EPA estimated in the RIA 

that the proposed rule could result in up 

to a 3 percent reduction in natural gas 

use in the power sector (or more than a 

25 MM MCF reduction in production on 

an annual basis). 

The energy impacts EPA estimates 

from the proposed rule may be underor over-estimates of the true energy 

impacts associated with this action. For 

example, some states are likely to 

pursue emissions reduction strategies 

independent of EPA action. 

J. National Technology Transfer and 

Advancement Act (NTTAA) 

This proposed rulemaking does not 

involve technical standards. EPA 

welcomes comments on this aspect of 

the proposed rulemaking and 

specifically invites the public to identify 

potentially-applicable voluntary 

consensus standards and to explain why 

such standards should be used in this 

action (Comment C–75). 

K. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

EPA believes that this proposed 

action is unlikely to have 

disproportionately high and adverse 

human health or environmental effects 

on minority populations, low-income 

populations and/or indigenous peoples 

as specified in Executive Order 12898 

(59 FR 7629, February 16, 1994). The 

CPP, as discussed in the RIA,71 was 

anticipated to reduce emissions of PM2.5

and ozone, and some of the benefits of 

reducing these pollutants would have 

accrued to minority populations, lowincome populations and/or indigenous 

peoples. While this proposal does not 

project to achieve reductions at the level 

of the CPP, EPA believes that this 

proposal will achieve CO2 emission 

reductions resulting from 

implementation of these proposed 

guidelines, as well as ozone and PM2.5

emission reductions as a co-benefit, and 

will further improve children’s health as 

discussed in the RIA. 

Moreover, this proposed action does 

not affect the level of public health and 

environmental protection already being 

provided by existing NAAQS, including 

ozone and PM2.5, and other mechanisms 

in the CAA. This proposed action does 

not affect applicable local, state, or 

federal permitting or air quality 

management programs that will 

continue to address areas with degraded 

air quality and maintain the air quality 

in areas meeting current standards. 

Areas that need to reduce criteria air 

pollution to meet the NAAQS will still 

need to rely on control strategies to 

reduce emissions. 

XI. Statutory Authority 

The statutory authority for this action 

is provided by sections 111, 301, and 

307(d)(1)(V) of the CAA, as amended (42 

U.S.C. 7411, 7601, 7607(d)(1)(V)). This 

action is also subject to section 307(d) 

of the CAA (42 U.S.C. 7607(d)). 

List of Subjects 

40 CFR Part 51 

Environmental protection, 

Intergovernmental relations, Reporting 

and recordkeeping requirements. 

40 CFR Part 52 

Environmental protection, Air 

pollution control, Incorporation by 

reference, Intergovernmental relations, 

Reporting and recordkeeping 

requirements. 

40 CFR Part 60 

Environmental protection, 

Administrative practice and procedure, 

Incorporation by reference, 

Intergovernmental relations, Reporting 

and recordkeeping requirements. 

Dated: August 20, 2018. 

Andrew R. Wheeler, 

Acting Administrator. 

For the reasons stated in the 

preamble, EPA proposes to amend 40 

CFR parts 51, 52, and 60 as set forth 

below: 

PART 51—REQUIREMENTS FOR 

PREPARATION, ADOPTION, AND 

SUBMITTAL OF IMPLEMENTATION 

PLANS 

■ 1. The authority citation for part 51 

continues to read as follows: 


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Authority: 23 U.S.C. 101; 42 U.S.C. 7401– 

7671q. 

Subpart I—Review of New Sources and 

Modifications 

■ 2. Add § 51.167 to read as follows: 

§ 51.167 Preliminary major NSR 

applicability test for electric generating 

units (EGUs). 

(a) What is the purpose of this 

section? State Implementation Plans 

(SIP) may incorporate the requirements 

in paragraphs (b) through (h) of this 

section for determining whether a 

change to an electric generating unit 

(EGU), as defined in § 51.124(q), is a 

modification for purposes of major NSR 

applicability. Deviations from these 

provisions will be approved only if the 

State demonstrates that the submitted 

provisions are at least as stringent in all 

respects as the corresponding provisions 

in paragraphs (b) through (h) of this 

section. 

(b) Am I subject to this section? You 

must meet the requirements of this 

section if your State incorporates these 

provisions in its SIP, and you own or 

operate an EGU that is located at a major 

stationary source, and you plan to make 

a change to the EGU. 

(c) What happens if a change to my 

EGU is determined to be a modification 

according to the procedures of this 

section? If the change to your EGU is a 

modification according to the 

procedures of this section, you must 

determine whether the change is a major 

modification according to the 

procedures of the major NSR program 

that applies in the area in which your 

EGU is located. That is, you must 

evaluate your modification according to 

the requirements set out in the 

applicable regulations approved 

pursuant to § 51.165 or § 51.166 

depending on the regulated NSR 

pollutants emitted and the attainment 

status of the area in which your EGU is 

located for those pollutants. Section 

51.165 sets out the requirements for 

State nonattainment major NSR 

programs, while § 51.166 sets out the 

requirements for State PSD programs. 

(d) What is the process for 

determining if a change to an EGU is a 

modification? The two-step process set 

out in paragraphs (d)(1) and (2) of this 

section is used to determine (before 

beginning actual construction) whether 

a change to an EGU located at a major 

stationary source is a modification. 

Regardless of any preconstruction 

projections, a modification has occurred 

if a change satisfies both steps in the 

process. 

(1) Step 1. Is the change a physical 

change in, or change in the method of 

operation of, the EGU? (See paragraph 

(e) of this section for a list of actions 

that are not physical or operational 

changes.) If so, go on to Step 2 

(paragraph (d)(2) of this section). 

(2) Step 2. Will the physical or 

operational change to the EGU increase 

the amount of any regulated NSR 

pollutant emitted into the atmosphere 

by the source (as determined according 

to paragraph (f) of this section) or result 

in the emissions of any regulated NSR 

pollutant(s) into the atmosphere that the 

source did not previously emit? If so, 

the change is a modification. 

(e) What types of actions are not 

physical changes or changes in the 

method of operation? (Step 1) For 

purposes of this section, a physical 

change or change in the method of 

operation shall not include: 

(1) Routine maintenance, repair, and 

replacement; 

(2) Use of an alternative fuel or raw 

material by reason of an order under 

sections 2(a) and (b) of the Energy 

Supply and Environmental 

Coordination Act of 1974 (or any 

superseding legislation) or by reason of 

a natural gas curtailment plan pursuant 

to the Federal Power Act; 

(3) Use of an alternative fuel by reason 

of an order or rule under section 125 of 

the Act; 

(4) Use of an alternative fuel at a 

steam generating unit to the extent that 

the fuel is generated from municipal 

solid waste; 

(5) Use of an alternative fuel or raw 

material by a stationary source which 

the source is approved to use under any 

permit issued under 40 CFR 52.21 or 

under regulations approved pursuant to 

§ 51.165 or § 51.166, or which: 

(i) For purposes of evaluating 

attainment pollutants, the source was 

capable of accommodating before 

January 6, 1975, unless such change 

would be prohibited under any federally 

enforceable permit condition which was 

established after January 6, 1975 

pursuant to 40 CFR 52.21 or under 

regulations approved pursuant to 

subpart I of this part; or 

(ii) For purposes of evaluating 

nonattainment pollutants, the source 

was capable of accommodating before 

December 21, 1976, unless such change 

would be prohibited under any federally 

enforceable permit condition which was 

established after December 21, 1976 

pursuant to 40 CFR 52.21 or under 

regulations approved pursuant to 

subpart I of this part; 

(6) An increase in the hours of 

operation or in the production rate, 

unless such change is prohibited under 

any federally enforceable permit 

condition which was established after 

January 6, 1975 (for purposes of 

evaluating attainment pollutants) or 

after December 21, 1976 (for purposes of 

evaluating nonattainment pollutants) 

pursuant to 40 CFR 52.21 or regulations 

approved pursuant to subpart I of this 

part; 

(7) Any change in ownership at a 

stationary source; 

(8) The installation, operation, 

cessation, or removal of a temporary 

clean coal technology demonstration 

project, provided that the project 

complies with: 

(i) The State Implementation Plan for 

the State in which the project is located; 

and 

(ii) Other requirements necessary to 

attain and maintain the national 

ambient air quality standard during the 

project and after it is terminated; 

(9) For purposes of evaluating 

attainment pollutants, the installation or 

operation of a permanent clean coal 

technology demonstration project that 

constitutes repowering, provided that 

the project does not result in an increase 

in the potential to emit of any regulated 

pollutant emitted by the unit. This 

exemption shall apply on a pollutantby-pollutant basis; or 

(10) For purposes of evaluating 

attainment pollutants, the reactivation 

of a very clean coal-fired EGU. 

(f) How do I determine if there is an 

emissions increase? (Step 2) You must 

determine if the physical or operational 

change to your EGU increases the 

amount of any regulated NSR pollutant 

emitted to the atmosphere using the 

method in paragraph (f)(1) of this 

section, subject to the limitations in 

paragraph (f)(2) of this section. If the 

physical or operational change to your 

EGU increases the amount of any 

regulated NSR pollutant emitted into 

the atmosphere or results in the 

emission of any regulated NSR 

pollutant(s) into the atmosphere that 

your EGU did not previously emit, the 

change is a modification as defined in 

paragraph (h)(2) of this section. 

Alternative 1 for paragraph (f)(1): 

(1) Emissions increase test. For each 

regulated NSR pollutant for which you 

have hourly average CEMS or PEMS 

emissions data with corresponding fuel 

heat input data, compare the pre-change 

maximum actual hourly emissions rate 

in pounds per hour (lb/hr) to a 

projection of the post-change maximum 

actual hourly emissions rate in lb/hr, 

subject to the provisions in paragraphs 

(f)(1)(i) through (iii) of this section. 

(i) Pre-change emissions. Determine 

the pre-change maximum actual hourly 

emissions rate as follows: 

(A) Select a period of 365 consecutive 

days within the 5-year period 


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immediately preceding when you begin 

actual construction of the physical or 

operational change. Compile a data set 

(for example, in a spreadsheet) with the 

hourly average CEMS or PEMS (as 

applicable) measured emissions rates 

and corresponding heat input data for 

all of the hours of operation for that 365- 

day period for the pollutant of interest. 

(B) Delete any unacceptable hourly 

data from this 365-day period in 

accordance with the data limitations in 

paragraph (f)(2) of this section. 

(C) Extract the hourly data for the 10 

percent of the remaining data set 

corresponding to the highest heat input 

rates for the selected period. This step 

may be facilitated by sorting the data set 

for the remaining operating hours from 

the lowest to the highest heat input 

rates. 

(D) Calculate the average emissions 

rate from the extracted (i.e., highest 10 

percent heat input rates) data set, using 

Equation 1: 

Where: 

x ̄ = average emissions rate, lb/hr; 

n = number of emissions rate values; and 

xi = ith emissions rate value, lb/hr. 

(E) Calculate the standard deviation of 

the data set using Equation 2: 

Where: 

s = standard deviation of the data set. 

(F) Calculate the Upper Tolerance 

Limit of the data set using Equation 3: 

Where: 

UTL = Upper Tolerance Limit of the data set; 

Z1¥p = 3.090, Z score for the 99.9 percentage 

of interval; and 

Z1¥q = 2.326, Z score for the 99 percent 

confidence level. 

(G) Use the UTL calculated in 

paragraph (f)(1)(i)(F) of this section as 

the pre-change maximum actual hourly 

emissions rate. 

(ii) Post-change emissions— 

preconstruction projections. For each 

regulated NSR pollutant, you must 

project the maximum emissions rate 

that your EGU will actually achieve in 

any 1 hour in the 5 years following the 

date the EGU resumes regular operation 

after the physical or operational change. 

An emissions increase results from the 

physical or operational change if this 

projected maximum actual hourly 

emissions rate exceeds the pre-change 

maximum actual hourly emissions rate. 

(iii) Post-change emissions-actually 

achieved. Regardless of any 

preconstruction projections, an 

emissions increase has occurred if the 

hourly emissions rate actually achieved 

in the 5 years after the change exceeds 

the pre-change maximum actual hourly 

emissions rate. 

Alternative 2 for paragraph (f)(1): 

(1) Emissions increase test. For each 

regulated NSR pollutant, compare the 

pre-change maximum actual hourly 

emissions rate in pounds per hour (lb/ 

hr) to a projection of the post-change 

maximum actual hourly emissions rate 

in lb/hr, subject to the provisions in 

paragraphs (f)(1)(i) through (iv) of this 

section. 

(i) Pre-change emissions—general 

procedures. The pre-change maximum 

actual hourly emissions rate for the 

pollutant is the highest emissions rate 

(lb/hr) actually achieved by the EGU for 

1 hour at any time during the 5-year 

period immediately preceding when 

you begin actual construction of the 

physical or operational change. 

(ii) Pre-change emissions—data 

sources. You must determine the 

highest pre-change hourly emissions 

rate for each regulated NSR pollutant 

using the best data available to you. Use 

the highest available source of data in 

the following hierarchy, unless your 

reviewing authority has determined that 

a data source lower in the hierarchy will 

provide better data for your EGU: 

(A) Continuous emissions monitoring 

system (CEMS). 


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(B) Approved predictive emissions 

monitoring system (PEMS). 

(C) Emission tests/emission factor 

specific to the EGU to be changed. 

(D) Material balance calculations. 

(E) Published emission factor. 

(iii) Post-change emissions— 

preconstruction projections. For each 

regulated NSR pollutant, you must 

project the maximum emissions rate 

that your EGU will actually achieve in 

any 1 hour in the 5 years following the 

date the EGU resumes regular operation 

after the physical or operational change. 

An emissions increase results from the 

physical or operational change if this 

projected maximum actual hourly 

emissions rate exceeds the pre-change 

maximum actual hourly emissions rate. 

(iv) Post-change emissions—actually 

achieved. Regardless of any 

preconstruction projections, an 

emissions increase has occurred if the 

hourly emissions rate actually achieved 

in the 5 years after the change exceeds 

the pre-change maximum actual hourly 

emissions rate. 

Alternative 3 for paragraph (f)(1): 

(1) Emissions increase test. For each 

regulated NSR pollutant, compare the 

maximum achievable hourly emissions 

rate before the physical or operational 

change to the maximum achievable 

hourly emissions rate after the change. 

Determine these maximum achievable 

hourly emissions rates according to 

§ 60.14(b) of this chapter. No physical 

change, or change in the method of 

operation, at an existing EGU shall be 

treated as a modification for the 

purposes of this section provided that 

such change does not increase the 

maximum hourly emissions of any 

regulated NSR pollutant above the 

maximum hourly emissions achievable 

at that unit during the 5 years prior to 

the change. 

(2) Data limitations for maximum 

emissions rates. For purposes of 

determining pre-change and postchange maximum emissions rates under 

paragraph (f)(1) of this section, the 

following limitations apply to the types 

of data that you may use: 

(i) Data limitations for Alternatives 1– 

2. (A) You must not use emissions rate 

data associated with startups, 

shutdowns, or malfunctions of your 

EGU, as defined by applicable 

regulation(s) or permit term(s), or 

malfunctions of an associated air 

pollution control device. A malfunction 

means any sudden, infrequent, and not 

reasonably preventable failure of the 

EGU or the air pollution control 

equipment to operate in a normal or 

usual manner. 

(B) You must not use continuous 

emissions monitoring system (CEMS) or 

predictive emissions monitoring system 

(PEMS) data recorded during 

monitoring system out-of-control 

periods. Out-of-control periods include 

those during which the monitoring 

system fails to meet quality assurance 

criteria (for example, periods of system 

breakdown, repair, calibration checks, 

or zero and span adjustments) 

established by regulation, by permit, or 

in an approved quality assurance plan. 

(C) You must not use emissions rate 

data from periods of noncompliance 

when your EGU was operating above an 

emission limitation that was legally 

enforceable at the time the data were 

collected. 

(D) You must not use data from any 

period for which the information is 

inadequate for determining emissions 

rates, including information related to 

the limitations in paragraphs (f)(2)(i)(A) 

through (C) of this section. 

(ii) Data limitations for Alternative 3. 

(A) You must not use emissions rate 

data associated with startups, 

shutdowns, or malfunctions of your 

EGU, as defined by applicable 

regulation(s) or permit term(s), or 

malfunctions of an associated air 

pollution control device. A malfunction 

means any sudden, infrequent, and not 

reasonably preventable failure of the 

EGU or the air pollution control 

equipment to operate in a normal or 

usual manner. 

(B) You must not use continuous 

emissions monitoring system (CEMS) or 

predictive emissions monitoring system 

(PEMS) data recorded during 

monitoring system out-of-control 

periods. Out-of-control periods include 

those during which the monitoring 

system fails to meet quality assurance 

criteria (for example, periods of system 

breakdown, repair, calibration checks, 

or zero and span adjustments) 

established by regulation, by permit, or 

in an approved quality assurance plan. 

(C) You must not use data from any 

period for which the information is 

inadequate for determining emissions 

rates, including information related to 

the limitations in paragraphs (f)(2)(ii)(A) 

and (B) of this section. 

(g) What are my requirements for 

recordkeeping? You must maintain a file 

of all information related to 

determinations that you make under 

this section of whether a change to an 

EGU is a modification, subject to the 

following provisions: 

(1) The file must include, but is not 

limited to, the following information 

recorded in permanent form suitable for 

inspection: 

(i) Continuous monitoring system, 

monitoring device, and performance 

testing measurements; 

(ii) All continuous monitoring system 

performance evaluations; 

(iii) All continuous monitoring system 

or monitoring device calibration checks; 

(iv) All adjustments and maintenance 

performed on these systems or devices; 

and 

(v) All other information relevant to 

any determination made under this 

section of whether a change to an EGU 

is a modification. 

(2) You must retain the file until the 

later of: 

(i) The date 5 years following the date 

the EGU resumes regular operation after 

the physical or operational change; and 

(ii) The date 5 years following the 

date of such measurements, 

maintenance, reports, and records. 

(h) What definitions apply under this 

section? The definitions of terms in 

§ 51.124(q) apply. Terms used in this 

section have the meaning accorded 

them under § 51.165(a)(1) or § 51.166(b), 

as appropriate. Terms not defined here 

or in § 51.165(a)(1) or § 51.166(b) (as 

appropriate) have the meaning accorded 

them under the applicable requirements 

of the Clean Air Act. 

PART 52—APPROVAL AND 

PROMULGATION OF 

IMPLEMENTATION PLANS 

■ 3. The authority citation for part 52 

continues to read as follows: 

Authority: 42 U.S.C. 7401 et seq. 

Subpart A—General Provisions 

■ 4. Add § 52.25 to read as follows: 

§ 52.25 Preliminary major NSR 

applicability test for electric generating 

units (EGUs). 

(a) What is the purpose of this 

section? The provisions of this section 

are applicable to any State 

implementation plan which has been 

disapproved with respect to prevention 

of significant deterioration of air quality 

in any portion of any State where the 

existing air quality is better than the 

national ambient air quality standards. 

Specific disapprovals are listed where 

applicable, in subparts B through DDD 

and FFF of this part. The provisions of 

this section have been incorporated by 

reference into the applicable 

implementation plans for various States, 

as provided in subparts B through DDD 

and FFF of this part. Where this section 

is so incorporated, the provisions shall 

also be applicable to all lands owned by 

the Federal Government and Indian 

Reservations located in such State. No 

disapproval with respect to a State’s 

failure to prevent significant 

deterioration of air quality shall 

invalidate or otherwise affect the 


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obligations of States, emission sources, 

or other persons with respect to all 

portions of plans approved or 

promulgated under this part. 

(b) Am I subject to this section? You 

must meet the requirements of this 

section if you own or operate an EGU 

that is located at a major stationary 

source, and you plan to make a change 

to the EGU. 

(c) What happens if a change to my 

EGU is determined to be a modification 

according to the procedures of this 

section? If the change to your electric 

generating unit (EGU), as defined in 

§ 51.124(q) of this chapter, is a 

modification according to the 

procedures of this section, you must 

determine whether the change is a major 

modification according to the 

procedures of the major NSR program 

that applies in the area in which your 

EGU is located. That is, you must 

evaluate your modification according to 

the requirements set out in the 

applicable regulations approved 

pursuant to § 52.21. 

(d) What is the process for 

determining if a change to an EGU is a 

modification? The two-step process set 

out in paragraphs (d)(1) and (2) of this 

section is used to determine (before 

beginning actual construction) whether 

a change to an EGU located at a major 

stationary source is a modification. 

Regardless of any preconstruction 

projections, a modification has occurred 

if a change satisfies both steps in the 

process. 

(1) Step 1. Is the change a physical 

change in, or change in the method of 

operation of, the EGU? (See paragraph 

(e) of this section for a list of actions 

that are not physical or operational 

changes.) If so, go on to Step 2 

(paragraph (d)(2) of this section). 

(2) Step 2. Will the physical or 

operational change to the EGU increase 

the amount of any regulated NSR 

pollutant emitted into the atmosphere 

by the source (as determined according 

to paragraph (f) of this section) or result 

in the emissions of any regulated NSR 

pollutant(s) into the atmosphere that the 

source did not previously emit? If so, 

the change is a modification. 

(e) What types of actions are not 

physical changes or changes in the 

method of operation? (Step 1) For 

purposes of this section, a physical 

change or change in the method of 

operation shall not include: 

(1) Routine maintenance, repair, and 

replacement; 

(2) Use of an alternative fuel or raw 

material by reason of an order under 

sections 2(a) and (b) of the Energy 

Supply and Environmental 

Coordination Act of 1974 (or any 

superseding legislation) or by reason of 

a natural gas curtailment plan pursuant 

to the Federal Power Act; 

(3) Use of an alternative fuel by reason 

of an order or rule under section 125 of 

the Act; 

(4) Use of an alternative fuel at a 

steam generating unit to the extent that 

the fuel is generated from municipal 

solid waste; 

(5) Use of an alternative fuel or raw 

material by a stationary source which 

the source is approved to use under any 

permit issued under 40 CFR 52.21 or 

under regulations approved pursuant to 

§ 51.166 of this chapter, or which the 

source was capable of accommodating 

before January 6, 1975, unless such 

change would be prohibited under any 

federally enforceable permit condition 

which was established after January 6, 

1975 pursuant to 40 CFR 52.21 or under 

regulations approved pursuant to 40 

CFR part 51, subpart I; or 

(6) An increase in the hours of 

operation or in the production rate, 

unless such change is prohibited under 

any federally enforceable permit 

condition which was established after 

January 6, 1975 pursuant to 40 CFR 

52.21 or regulations approved pursuant 

to 40 CFR part 51, subpart I; 

(7) Any change in ownership at a 

stationary source; 

(8) The installation, operation, 

cessation, or removal of a temporary 

clean coal technology demonstration 

project, provided that the project 

complies with: 

(i) The State Implementation Plan for 

the State in which the project is located; 

and 

(ii) Other requirements necessary to 

attain and maintain the national 

ambient air quality standard during the 

project and after it is terminated; 

(9) For purposes of evaluating 

attainment pollutants, the installation or 

operation of a permanent clean coal 

technology demonstration project that 

constitutes repowering, provided that 

the project does not result in an increase 

in the potential to emit of any regulated 

pollutant emitted by the unit. This 

exemption shall apply on a pollutantby-pollutant basis; or 

(10) For purposes of evaluating 

attainment pollutants, the reactivation 

of a very clean coal-fired EGU. 

(f) How do I determine if there is an 

emissions increase? (Step 2) You must 

determine if the physical or operational 

change to your EGU increases the 

amount of any regulated NSR pollutant 

emitted to the atmosphere using the 

method in paragraph (f)(1) of this 

section, subject to the limitations in 

paragraph (f)(2) of this section. If the 

physical or operational change to your 

EGU increases the amount of any 

regulated NSR pollutant emitted into 

the atmosphere or results in the 

emission of any regulated NSR 

pollutant(s) into the atmosphere that 

your EGU did not previously emit, the 

change is a modification as defined in 

paragraph (h)(2) of this section. 

Alternative 1 for paragraph (f)(1): 

(1) Emissions increase test. For each 

regulated NSR pollutant for which you 

have hourly average CEMS or PEMS 

emissions data with corresponding fuel 

heat input data, compare the pre-change 

maximum actual hourly emissions rate 

in pounds per hour (lb/hr) to a 

projection of the post-change maximum 

actual hourly emissions rate in lb/hr, 

subject to the provisions in paragraphs 

(f)(1)(i) through (iii) of this section. 

(i) Pre-change emissions. Determine 

the pre-change maximum actual hourly 

emissions rate as follows: 

(A) Select a period of 365 consecutive 

days within the 5-year period 

immediately preceding when you begin 

actual construction of the physical or 

operational change. Compile a data set 

(for example, in a spreadsheet) with the 

hourly average CEMS or PEMS (as 

applicable) measured emissions rates 

and corresponding heat input data for 

all of the hours of operation for that 365- 

day period for the pollutant of interest. 

(B) Delete any unacceptable hourly 

data from this 365-day period in 

accordance with the data limitations in 

paragraph (f)(2) of this section. 

(C) Extract the hourly data for the 10 

percent of the remaining data set 

corresponding to the highest heat input 

rates for the selected period. This step 

may be facilitated by sorting the data set 

for the remaining operating hours from 

the lowest to the highest heat input 

rates. 

(D) Calculate the average emissions 

rate from the extracted (i.e., highest 10 

percent heat input rates) data set, using 

Equation 1: 


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Where: 

x ̄ = average emissions rate, lb/hr; 

n = number of emissions rate values; and 

xi = ith emissions rate value, lb/hr. 

(E) Calculate the standard deviation of 

the data set using Equation 2: 

Where: 

s = standard deviation of the data set. 

(F) Calculate the Upper Tolerance 

Limit of the data set using Equation 3: 

Where: 

UTL = Upper Tolerance Limit of the data set; 

Z1¥p = 3.090, Z score for the 99.9 percentage 

of interval; and 

Z1¥q = 2.326, Z score for the 99 percent 

confidence level. 

(G) Use the UTL calculated in 

paragraph (f)(1)(i)(F) of this section as 

the pre-change maximum actual hourly 

emissions rate. 

(ii) Post-change emissions— 

preconstruction projections. For each 

regulated NSR pollutant, you must 

project the maximum emissions rate 

that your EGU will actually achieve in 

any 1 hour in the 5 years following the 

date the EGU resumes regular operation 

after the physical or operational change. 

An emissions increase results from the 

physical or operational change if this 

projected maximum actual hourly 

emissions rate exceeds the pre-change 

maximum actual hourly emissions rate. 

(iii) Post-change emissions—actually 

achieved. Regardless of any 

preconstruction projections, an 

emissions increase has occurred if the 

hourly emissions rate actually achieved 

in the 5 years after the change exceeds 

the pre-change maximum actual hourly 

emissions rate. 

Alternative 2 for paragraph (f)(1): 

(1) Emissions increase test. For each 

regulated NSR pollutant, compare the 

pre-change maximum actual hourly 

emissions rate in pounds per hour (lb/ 

hr) to a projection of the post-change 

maximum actual hourly emissions rate 

in lb/hr, subject to the provisions in 

paragraphs (f)(1)(i) through (iv) of this 

section. 

(i) Pre-change emissions—general 

procedures. The pre-change maximum 

actual hourly emissions rate for the 

pollutant is the highest emissions rate 

(lb/hr) actually achieved by the EGU for 

1 hour at any time during the 5-year 

period immediately preceding when 

you begin actual construction of the 

physical or operational change. 

(ii) Pre-change emissions—data 

sources. You must determine the 

highest pre-change hourly emissions 

rate for each regulated NSR pollutant 

using the best data available to you. Use 

the highest available source of data in 

the following hierarchy, unless your 

reviewing authority has determined that 

a data source lower in the hierarchy will 

provide better data for your EGU: 

(A) Continuous emissions monitoring 

system (CEMS). 

(B) Approved predictive emissions 

monitoring system (PEMS). 

(C) Emission tests/emission factor 

specific to the EGU to be changed. 

(D) Material balance calculations. 

(E) Published emission factor. 

(iii) Post-change emissions— 

preconstruction projections. For each 

regulated NSR pollutant, you must 

project the maximum emissions rate 

that your EGU will actually achieve in 

any 1 hour in the 5 years following the 

date the EGU resumes regular operation 

after the physical or operational change. 

An emissions increase results from the 

physical or operational change if this 

projected maximum actual hourly 

emissions rate exceeds the pre-change 

maximum actual hourly emissions rate. 

(iv) Post-change emissions—actually 

achieved. Regardless of any 

preconstruction projections, an 

emissions increase has occurred if the 

hourly emissions rate actually achieved 

in the 5 years after the change exceeds 

the pre-change maximum actual hourly 

emissions rate. 

Alternative 3 for paragraph (f)(1): 

(1) Emissions increase test. For each 

regulated NSR pollutant, compare the 

maximum achievable hourly emissions 

rate before the physical or operational 

change to the maximum achievable 

hourly emissions rate after the change. 

Determine these maximum achievable 


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hourly emissions rates according to 

§ 60.14(b) of this chapter. No physical 

change, or change in the method of 

operation, at an existing EGU shall be 

treated as a modification for the 

purposes of this section provided that 

such change does not increase the 

maximum hourly emissions of any 

regulated NSR pollutant above the 

maximum hourly emissions achievable 

at that unit during the 5 years prior to 

the change. 

(2) Data limitations for maximum 

emissions rates. For purposes of 

determining pre-change and postchange maximum emissions rates under 

paragraph (f)(1) of this section, the 

following limitations apply to the types 

of data that you may use: 

(i) Data limitations for Alternatives 1– 

2. (A) You must not use emissions rate 

data associated with startups, 

shutdowns, or malfunctions of your 

EGU, as defined by applicable 

regulation(s) or permit term(s), or 

malfunctions of an associated air 

pollution control device. A malfunction 

means any sudden, infrequent, and not 

reasonably preventable failure of the 

EGU or the air pollution control 

equipment to operate in a normal or 

usual manner. 

(B) You must not use continuous 

emissions monitoring system (CEMS) or 

predictive emissions monitoring system 

(PEMS) data recorded during 

monitoring system out-of-control 

periods. Out-of-control periods include 

those during which the monitoring 

system fails to meet quality assurance 

criteria (for example, periods of system 

breakdown, repair, calibration checks, 

or zero and span adjustments) 

established by regulation, by permit, or 

in an approved quality assurance plan. 

(C) You must not use emissions rate 

data from periods of noncompliance 

when your EGU was operating above an 

emission limitation that was legally 

enforceable at the time the data were 

collected. 

(D) You must not use data from any 

period for which the information is 

inadequate for determining emissions 

rates, including information related to 

the limitations in paragraphs (f)(2)(i)(A) 

through (C) of this section. 

(ii) Data limitations for Alternative 3. 

(A) You must not use emissions rate 

data associated with startups, 

shutdowns, or malfunctions of your 

EGU, as defined by applicable 

regulation(s) or permit term(s), or 

malfunctions of an associated air 

pollution control device. A malfunction 

means any sudden, infrequent, and not 

reasonably preventable failure of the 

EGU or the air pollution control 

equipment to operate in a normal or 

usual manner. 

(B) You must not use continuous 

emissions monitoring system (CEMS) or 

predictive emissions monitoring system 

(PEMS) data recorded during 

monitoring system out-of-control 

periods. Out-of-control periods include 

those during which the monitoring 

system fails to meet quality assurance 

criteria (for example, periods of system 

breakdown, repair, calibration checks, 

or zero and span adjustments) 

established by regulation, by permit, or 

in an approved quality assurance plan. 

(C) You must not use data from any 

period for which the information is 

inadequate for determining emissions 

rates, including information related to 

the limitations in paragraphs (f)(2)(ii)(A) 

and (B) of this section. 

(g) What are my requirements for 

recordkeeping? You must maintain a file 

of all information related to 

determinations that you make under 

this section of whether a change to an 

EGU is a modification, subject to the 

following provisions: 

(1) The file must include, but is not 

limited to, the following information 

recorded in permanent form suitable for 

inspection: 

(i) Continuous monitoring system, 

monitoring device, and performance 

testing measurements; 

(ii) All continuous monitoring system 

performance evaluations; 

(iii) All continuous monitoring system 

or monitoring device calibration checks; 

(iv) All adjustments and maintenance 

performed on these systems or devices; 

and 

(v) All other information relevant to 

any determination made under this 

section of whether a change to an EGU 

is a modification. 

(2) You must retain the file until the 

later of: 

(i) The date 5 years following the date 

the EGU resumes regular operation after 

the physical or operational change; and 

(ii) The date 5 years following the 

date of such measurements, 

maintenance, reports, and records. 

(h) What definitions apply under this 

section? The definitions of terms in 

§ 51.124(q) of this chapter apply. Terms 

used in this section have the meaning 

accorded them under § 52.21. Terms not 

defined here or in § 52.21 have the 

meaning accorded them under the 

applicable requirements of the Clean Air 

Act. 

PART 60—STANDARDS OF 

PERFORMANCE FOR NEW 

STATIONARY SOURCES 

■ 5. The authority citation for part 60 

continues to read as follows: 

Authority: 42 U.S.C. 7401 et seq. 

■ 6. Add subpart Ba to read as follows: 

Subpart Ba—Adoption and Submittal of 

State Plans for Designated Facilities 

Sec. 

60.20a Applicability. 

60.21a Definitions. 

60.22a Publication of emission guidelines. 

60.23a Adoption and submittal of State 

plans; public hearings. 

60.24a Standards of performance and 

compliance schedules. 

60.25a Emission inventories, source 

surveillance, reports. 

60.26a Legal authority. 

60.27a Actions by the Administrator. 

60.28a Plan revisions by the State. 

60.29a Plan revisions by the Administrator. 

Subpart Ba—Adoption and Submittal 

of State Plans for Designated Facilities 

§ 60.20a Applicability. 

(a) The provisions of this subpart 

apply to States upon publication of a 

final emission guideline under 

§ 60.22a(a), if such final guideline is 

published after [date of publication of 

final rule in the Federal Register]. 

(1) Each emission guideline 

promulgated under this part is subject to 

the requirements of this subpart, except 

that each emission guideline may 

include specific provisions in addition 

to or that supersede requirements of this 

subpart. Each emission guideline must 

identify explicitly any provision of this 

subpart that is superseded. 

(2) Terms used throughout this part 

are defined in § 60.21a or in the Clean 

Air Act (Act) as amended in 1990, 

except that emission guidelines 

promulgated as individual subparts of 

this part may include specific 

definitions in addition to or that 

supersede definitions in § 60.21a. 

(b) No standard of performance or 

other requirement established under 

this part shall be interpreted, construed, 

or applied to diminish or replace the 

requirements of a more stringent 

emission limitation or other applicable 

requirement established by the 

Administrator pursuant to other 

authority of the Act (section 112, Part C 

or D, or any other authority of the Act), 

or a standard issued under State 

authority. The Administrator may 

specify in a specific standard under this 

part that facilities subject to other 

provisions under the Act need only 

comply with the provisions of that 

standard. 

§ 60.21a Definitions. 

Terms used but not defined in this 

subpart shall have the meaning given 

them in the Act and in subpart A: 

(a) Designated pollutant means any 

air pollutant, the emissions of which are 


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subject to a standard of performance for 

new stationary sources, but for which 

air quality criteria have not been issued 

and that is not included on a list 

published under section 108(a) or 

section 112(b) of the Act. 

(b) Designated facility means any 

existing facility (see § 60.2a(aa)) which 

emits a designated pollutant and which 

would be subject to a standard of 

performance for that pollutant if the 

existing facility were an affected facility 

(see § 60.2a(e)). 

(c) Plan means a plan under section 

111(d) of the Act which establishes 

standards of performance for designated 

pollutants from designated facilities and 

provides for the implementation and 

enforcement of such standards of 

performance. 

(d) Applicable plan means the plan, 

or most recent revision thereof, which 

has been approved under § 60.27a(b) or 

promulgated under § 60.27a(d). 

(e) Emission guideline means a final 

guideline document published under 

§ 60.22a(a), which includes information 

on the degree of emission reduction 

achievable through the application of 

the best system of emission reduction 

which (taking into account the cost of 

such reduction and any nonair quality 

health and environmental impact and 

energy requirements) the Administrator 

has determined has been adequately 

demonstrated for designated facilities. 

(f) Standard of performance means a 

standard for emissions of air pollutants 

which reflects the degree of emission 

limitation achievable through the 

application of the best system of 

emission reduction which (taking into 

account the cost of achieving such 

reduction and any nonair quality health 

and environmental impact and energy 

requirements) the Administrator 

determines has been adequately 

demonstrated, including, but not 

limited to,a legally enforceable 

regulation setting forth an allowable rate 

or limit of emissions into the 

atmosphere, or prescribing a design, 

equipment, work practice, or 

operational standard, or combination 

thereof. 

(g) Compliance schedule means a 

legally enforceable schedule specifying 

a date or dates by which a source or 

category of sources must comply with 

specific standards of performance 

contained in a plan or with any 

increments of progress to achieve such 

compliance. 

(h) Increments of progress means 

steps to achieve compliance which must 

be taken by an owner or operator of a 

designated facility, including: 

(1) Submittal of a final control plan 

for the designated facility to the 

appropriate air pollution control agency; 

(2) Awarding of contracts for emission 

control systems or for process 

modifications, or issuance of orders for 

the purchase of component parts to 

accomplish emission control or process 

modification; 

(3) Initiation of on-site construction or 

installation of emission control 

equipment or process change; 

(4) Completion of on-site construction 

or installation of emission control 

equipment or process change; and 

(5) Final compliance. 

(i) Region means an air quality control 

region designated under section 107 of 

the Act and described in part 81 of this 

chapter. 

(j) Local agency means any local 

governmental agency. 

§ 60.22a Publication of emission 

guidelines. 

(a) Concurrently upon or after 

proposal of standards of performance for 

the control of a designated pollutant 

from affected facilities, the 

Administrator will publish a draft 

emission guideline containing 

information pertinent to control of the 

designated pollutant from designated 

facilities. Notice of the availability of 

the draft emission guideline will be 

published in the Federal Register and 

public comments on its contents will be 

invited. After consideration of public 

comments, a final emission guideline 

will be published and notice of its 

availability will be published in the 

Federal Register. 

(b) Emission guidelines published 

under this section will provide 

information for the development of 

State plans, such as: 

(1) A description of systems of 

emission reduction which, in the 

judgment of the Administrator, have 

been adequately demonstrated. 

(2) Information on the degree of 

emission reduction which is achievable 

with each system, together with 

information on the costs, nonair quality 

health environmental effects, and 

energy requirements of applying each 

system to designated facilities. 

(3) Incremental periods of time 

normally expected to be necessary for 

the design, installation, and startup of 

identified control systems. 

(4) An emission guideline that reflects 

the application of the best system of 

emission reduction (considering the cost 

of such achieving reduction and any 

nonair quality health and environmental 

impact and energy requirements) that 

has been adequately demonstrated for 

designated facilities, and the time 

within which compliance with 

standards of performance can be 

achieved. The Administrator may 

specify different emission guidelines or 

compliance times or both for different 

sizes, types, and classes of designated 

facilities when costs of control, physical 

limitations, geographical location, or 

similar factors make subcategorization 

appropriate. 

(5) Such other available information 

as the Administrator determines may 

contribute to the formulation of State 

plans. 

§ 60.23a Adoption and submittal of State 

plans; public hearings. 

(a)(1) Unless otherwise specified in 

the applicable subpart, within three 

years after notice of the availability of a 

final emission guideline is published 

under § 60.22a(a), each State shall adopt 

and submit to the Administrator, in 

accordance with § 60.4, a plan for the 

control of the designated pollutant to 

which the emission guideline applies. 

(2) At any time, each State may adopt 

and submit to the Administrator any 

plan revision necessary to meet the 

requirements of this subpart or an 

applicable subpart of this part. 

(b) If no designated facility is located 

within a State, the State shall submit a 

letter of certification to that effect to the 

Administrator within the time specified 

in paragraph (a) of this section. Such 

certification shall exempt the State from 

the requirements of this subpart for that 

designated pollutant. 

(c) The State shall, prior to the 

adoption of any plan or revision thereof, 

conduct one or more public hearings 

within the State on such plan or plan 

revision. 

(d) Any hearing required by paragraph 

(c) of this section shall be held only 

after reasonable notice. Notice shall be 

given at least 30 days prior to the date 

of such hearing and shall include: 

(1) Notification to the public by 

prominently advertising the date, time, 

and place of such hearing in each region 

affected. This requirement may be 

satisfied by advertisement on the 

internet; 

(2) Availability, at the time of public 

announcement, of each proposed plan 

or revision thereof for public inspection 

in at least one location in each region to 

which it will apply. This requirement 

may be satisfied by posting each 

proposed plan or revision on the 

internet; 

(3) Notification to the Administrator; 

(4) Notification to each local air 

pollution control agency in each region 

to which the plan or revision will apply; 

and 


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(5) In the case of an interstate region, 

notification to any other State included 

in the region. 

(e) The State may cancel the public 

hearing through a method it identifies if 

no request for a public hearing is 

received during the 30 day notification 

period under subsection (d) and the 

original notice announcing the 30 day 

notification period states that if no 

request for a public hearing is received 

the hearing will be cancelled; identifies 

the method and time for announcing 

that the hearing has been cancelled; and 

provides a contact phone number for the 

public to call to find out if the hearing 

has been cancelled. 

(f) The State shall prepare and retain, 

for a minimum of 2 years, a record of 

each hearing for inspection by any 

interested party. The record shall 

contain, as a minimum, a list of 

witnesses together with the text of each 

presentation. 

(g) The State shall submit with the 

plan or revision: 

(1) Certification that each hearing 

required by paragraph (c) of this section 

was held in accordance with the notice 

required by paragraph (d) of this 

section; and 

(2) A list of witnesses and their 

organizational affiliations, if any, 

appearing at the hearing and a brief 

written summary of each presentation or 

written submission. 

(h) Upon written application by a 

State agency (through the appropriate 

Regional Office), the Administrator may 

approve State procedures designed to 

insure public participation in the 

matters for which hearings are required 

and public notification of the 

opportunity to participate if, in the 

judgment of the Administrator, the 

procedures, although different from the 

requirements of this subpart, in fact 

provide for adequate notice to and 

participation of the public. The 

Administrator may impose such 

conditions on his approval as he deems 

necessary. Procedures approved under 

this section shall be deemed to satisfy 

the requirements of this subpart 

regarding procedures for public 

hearings. 

§ 60.24a Standards of performance and 

compliance schedules. 

(a) Each plan shall include standards 

of performance and compliance 

schedules. 

(b) Standards of performance shall 

either be based on allowable rate or 

limit of emissions, except when it is not 

feasible to prescribe or enforce a 

standard of performance. The EPA shall 

identify such cases in the emission 

guidelines issued under § 60.22a. Where 

standards of performance prescribing 

design, equipment, work practice, or 

operational standard, or combination 

thereof are established, the plan shall, to 

the degree possible, set forth the 

emission reductions achievable by 

implementation of such standards, and 

may permit compliance by the use of 

equipment determined by the State to be 

equivalent to that prescribed. 

(1) Test methods and procedures for 

determining compliance with the 

standards of performance shall be 

specified in the plan. Methods other 

than those specified in appendix A to 

this part or an applicable subpart of this 

part may be specified in the plan if 

shown to be equivalent or alternative 

methods as defined in § 60.2(t) and (u). 

(2) Standards of performance shall 

apply to all designated facilities within 

the State. A plan may contain standards 

of performance adopted by local 

jurisdictions provided that the 

standards are enforceable by the State. 

(c) Except as provided in paragraph 

(e) of this section, standards of 

performance shall be no less stringent 

than the corresponding emission 

guideline(s) specified in subpart C of 

this part, and final compliance shall be 

required as expeditiously as practicable, 

but no later than the compliance times 

specified in an applicable subpart of 

this part. 

(d)(1) Any compliance schedule 

extending more than 24 months from 

the date required for submittal of the 

plan must include legally enforceable 

increments of progress to achieve 

compliance for each designated facility 

or category of facilities. Unless 

otherwise specified in the applicable 

subpart, increments of progress must 

include, where practicable, each 

increment of progress specified in 

§ 60.21a(h) and must include such 

additional increments of progress as 

may be necessary to permit close and 

effective supervision of progress toward 

final compliance. 

(2) A plan may provide that 

compliance schedules for individual 

sources or categories of sources will be 

formulated after plan submittal. Any 

such schedule shall be the subject of a 

public hearing held according to 

§ 60.23a and shall be submitted to the 

Administrator within 60 days after the 

date of adoption of the schedule but in 

no case later than the date prescribed for 

submittal of the first semiannual report 

required by § 60.25a(e). 

(e) In applying a standard of 

performance to a particular source, the 

State may take into consideration 

factors, such as the remaining useful life 

of such source, provided that the State 

demonstrates with respect to each such 

facility (or class of such facilities): 

(1) Unreasonable cost of control 

resulting from plant age, location, or 

basic process design; 

(2) Physical impossibility of installing 

necessary control equipment; or 

(3) Other factors specific to the facility 

(or class of facilities) that make 

application of a less stringent standard 

or final compliance time significantly 

more reasonable. 

(f) Nothing in this subpart shall be 

construed to preclude any State or 

political subdivision thereof from 

adopting or enforcing: 

(1) Standards of performance more 

stringent than emission guidelines 

specified in subpart C of this part or in 

applicable emission guidelines; or 

(2) Compliance schedules requiring 

final compliance at earlier times than 

those specified in subpart C or in 

applicable emission guidelines. 

§ 60.25a Emission inventories, source 

surveillance, reports. 

(a) Each plan shall include an 

inventory of all designated facilities, 

including emission data for the 

designated pollutants and information 

related to emissions as specified in 

appendix D to this part. Such data shall 

be summarized in the plan, and 

emission rates of designated pollutants 

from designated facilities shall be 

correlated with applicable standards of 

performance. As used in this subpart, 

‘‘correlated’’ means presented in such a 

manner as to show the relationship 

between measured or estimated 

amounts of emissions and the amounts 

of such emissions allowable under 

applicable standards of performance. 

(b) Each plan shall provide for 

monitoring the status of compliance 

with applicable standards of 

performance. Each plan shall, as a 

minimum, provide for: 

(1) Legally enforceable procedures for 

requiring owners or operators of 

designated facilities to maintain records 

and periodically report to the State 

information on the nature and amount 

of emissions from such facilities, and/or 

such other information as may be 

necessary to enable the State to 

determine whether such facilities are in 

compliance with applicable portions of 

the plan. Submission of electronic 

documents shall comply with the 

requirements of 40 CFR part 3— 

(Electronic reporting). 

(2) Periodic inspection and, when 

applicable, testing of designated 

facilities. 

(c) Each plan shall provide that 

information obtained by the State under 

paragraph (b) of this section shall be 


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correlated with applicable standards of 

performance (see § 60.25a(a)) and made 

available to the general public. 

(d) The provisions referred to in 

paragraphs (b) and (c) of this section 

shall be specifically identified. Copies 

of such provisions shall be submitted 

with the plan unless: 

(1) They have been approved as 

portions of a preceding plan submitted 

under this subpart or as portions of an 

implementation plan submitted under 

section 110 of the Act, and 

(2) The State demonstrates: 

(i) That the provisions are applicable 

to the designated pollutant(s) for which 

the plan is submitted, and 

(ii) That the requirements of § 60.26a 

are met. 

(e) The State shall submit reports on 

progress in plan enforcement to the 

Administrator on an annual (calendar 

year) basis, commencing with the first 

full report period after approval of a 

plan or after promulgation of a plan by 

the Administrator. Information required 

under this paragraph must be included 

in the annual report required by 

§ 51.321 of this chapter. 

(f) Each progress report shall include: 

(1) Enforcement actions initiated 

against designated facilities during the 

reporting period, under any standard of 

performance or compliance schedule of 

the plan. 

(2) Identification of the achievement 

of any increment of progress required by 

the applicable plan during the reporting 

period. 

(3) Identification of designated 

facilities that have ceased operation 

during the reporting period. 

(4) Submission of emission inventory 

data as described in paragraph (a) of this 

section for designated facilities that 

were not in operation at the time of plan 

development but began operation 

during the reporting period. 

(5) Submission of additional data as 

necessary to update the information 

submitted under paragraph (a) of this 

section or in previous progress reports. 

(6) Submission of copies of technical 

reports on all performance testing on 

designated facilities conducted under 

paragraph (b)(2) of this section, 

complete with concurrently recorded 

process data. 

§ 60.26a Legal authority. 

(a) Each plan shall show that the State 

has legal authority to carry out the plan, 

including authority to: 

(1) Adopt standards of performance 

and compliance schedules applicable to 

designated facilities. 

(2) Enforce applicable laws, 

regulations, standards, and compliance 

schedules, and seek injunctive relief. 

(3) Obtain information necessary to 

determine whether designated facilities 

are in compliance with applicable laws, 

regulations, standards, and compliance 

schedules, including authority to 

require recordkeeping and to make 

inspections and conduct tests of 

designated facilities. 

(4) Require owners or operators of 

designated facilities to install, maintain, 

and use emission monitoring devices 

and to make periodic reports to the State 

on the nature and amounts of emissions 

from such facilities; also authority for 

the State to make such data available to 

the public as reported and as correlated 

with applicable standards of 

performance. 

(b) The provisions of law or 

regulations which the State determines 

provide the authorities required by this 

section shall be specifically identified. 

Copies of such laws or regulations shall 

be submitted with the plan unless: 

(1) They have been approved as 

portions of a preceding plan submitted 

under this subpart or as portions of an 

implementation plan submitted under 

section 110 of the Act, and 

(2) The State demonstrates that the 

laws or regulations are applicable to the 

designated pollutant(s) for which the 

plan is submitted. 

(c) The plan shall show that the legal 

authorities specified in this section are 

available to the State at the time of 

submission of the plan. Legal authority 

adequate to meet the requirements of 

paragraphs (a)(3) and (4) of this section 

may be delegated to the State under 

section 114 of the Act. 

(d) A State governmental agency other 

than the State air pollution control 

agency may be assigned responsibility 

for carrying out a portion of a plan if the 

plan demonstrates to the 

Administrator’s satisfaction that the 

State governmental agency has the legal 

authority necessary to carry out that 

portion of the plan. 

(e) The State may authorize a local 

agency to carry out a plan, or portion 

thereof, within the local agency’s 

jurisdiction if the plan demonstrates to 

the Administrator’s satisfaction that the 

local agency has the legal authority 

necessary to implement the plan or 

portion thereof, and that the 

authorization does not relieve the State 

of responsibility under the Act for 

carrying out the plan or portion thereof. 

§ 60.27a Actions by the Administrator. 

(a) The Administrator may, whenever 

he determines necessary, shorten the 

period for submission of any plan or 

plan revision or portion thereof. 

(b) After determination that a plan or 

plan revision is complete per the 

requirements of paragraph (g) of this 

section, the Administrator will take 

action on the plan or revision. The 

Administrator will, within twelve 

months of finding that a plan or plan 

revision is complete, approve or 

disapprove such plan or revision or 

each portion thereof. 

(c) The Administrator will propose to 

promulgate, through notice and 

comment rulemaking, a federal plan, or 

portion thereof, for a State if: 

(1) The Administrator finds that a 

State fails to submit a required complete 

plan or complete plan revision within 

the time prescribed; or 

(2) The Administrator disapproves the 

required State plan or plan revision or 

any portion thereof, as unsatisfactory 

because the applicable requirements of 

this subpart or an applicable subpart 

under this part have not been met. 

(d) The Administrator will, at any 

time within two years after the finding 

of failure to submit a complete plan or 

disapproval described under paragraph 

(c) of this section, promulgate a final 

federal plan unless, prior to such 

promulgation, the State has adopted and 

submitted a plan or plan revision which 

the Administrator determines to be 

approvable. 

(e)(1) Except as provided in paragraph 

(e)(2) of this section, a federal plan 

promulgated by the Administrator 

under this section will prescribe 

standards of performance of the same 

stringency as the corresponding 

emission guideline(s) specified in the 

final emission guideline published 

under § 60.22a(a) and will require 

compliance with such standards as 

expeditiously as practicable but no later 

than the times specified in the emission 

guideline. 

(2) Upon application by the owner or 

operator of a designated facility to 

which regulations proposed and 

promulgated under this section will 

apply, the Administrator may provide 

for the application of less stringent 

standards of performance or longer 

compliance schedules than those 

otherwise required by this section in 

accordance with the criteria specified in 

§ 60.24a(f). 

(f) Prior to promulgation of a federal 

plan under paragraph (d) of this section, 

the Administrator will provide the 

opportunity for at least one public 

hearing in either: 

(1) Each State that failed to hold a 

public hearing as required by 

§ 60.23a(c); or 

(2) Washington, DC or an alternate 

location specified in the Federal 

Register. 

(g) Each plan or plan revision that is 

submitted to the Administrator shall be 


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reviewed for completeness as described 

in paragraphs (g)(1) through (g)(3) of this 

section. 

(1) General. Within 60 days of the 

Administrator’s receipt of a state 

submission, but no later than 6 months 

after the date, if any, by which a State 

is required to submit the plan or 

revision, the Administrator shall 

determine whether the minimum 

criteria for completeness have been met. 

Any plan or plan revision that a State 

submits to the EPA, and that has not 

been determined by the EPA by the date 

6 months after receipt of the submission 

to have failed to meet the minimum 

criteria, shall on that date be deemed by 

operation of law to meet such minimum 

criteria. Where the Administrator 

determines that a plan submission does 

not meet the minimum criteria of this 

paragraph, the State will be treated as 

not having made the submission and the 

requirements of this section regarding 

promulgation of a federal plan shall 

apply. 

(2) Administrative criteria. In order to 

be deemed complete, a State plan must 

contain each of the following 

administrative criteria: 

(i) A formal letter of submittal from 

the Governor or her designee requesting 

EPA approval of the plan or revision 

thereof; 

(ii) Evidence that the State has 

adopted the plan in the state code or 

body of regulations. That evidence must 

include the date of adoption or final 

issuance as well as the effective date of 

the plan, if different from the adoption/ 

issuance date; 

(iii) Evidence that the State has the 

necessary legal authority under state 

law to adopt and implement the plan; 

(iv) A copy of the actual regulation, or 

document submitted for approval and 

incorporation by reference into the plan. 

The submittal must be a copy of the 

official state regulation or document 

signed, stamped and dated by the 

appropriate state official indicating that 

it is fully enforceable by the State. The 

effective date of the regulation or 

document must, whenever possible, be 

indicated in the document itself. The 

State’s electronic copy must be an exact 

duplicate of the hard copy. For revisions 

to the approved plan, the submittal 

must indicate the changes made (for 

example, by redline/strikethrough) to 

the approved plan; 

(v) Evidence that the State followed 

all of the procedural requirements of the 

state’s laws and constitution in 

conducting and completing the 

adoption and issuance of the plan; 

(vi) Evidence that public notice was 

given of the proposed change with 

procedures consistent with the 

requirements of § 60.23, including the 

date of publication of such notice; 

(vii) Certification that public 

hearing(s) were held in accordance with 

the information provided in the public 

notice and the State’s laws and 

constitution, if applicable and 

consistent with the public hearing 

requirements in § 60.23; 

(viii) Compilation of public comments 

and the State’s response thereto; and 

(ix) Such other criteria for 

completeness as may be specified by the 

Administrator under the applicable 

emission guidelines. 

(3) Technical criteria. In order to be 

deemed complete, a State plan must 

contain each of the following technical 

criteria: 

(i) Description of the plan approach 

and geographic scope; 

(ii) Identification of each affected 

source, identification of emission 

standards for the affected sources, and 

monitoring, recordkeeping and 

reporting requirements that will 

determine compliance by each affected 

source; 

(iii) Identification of compliance 

schedules and/or increments of 

progress; 

(iv) Demonstration that the State plan 

submittal is projected to achieve 

emissions performance under the 

applicable emission guidelines; 

(v) Documentation of state 

recordkeeping and reporting 

requirements to determine the 

performance of the plan as a whole; and 

(vi) Demonstration that each emission 

standard is quantifiable, nonduplicative, permanent, verifiable, and 

enforceable. 

§ 60.28a Plan revisions by the State. 

(a) Plan revisions shall be submitted 

to the Administrator within 12 months, 

or shorter if required by the 

Administrator, after notice of the 

availability of a final revised emission 

guideline is published under § 60.22a, 

in accordance with the procedures and 

requirements applicable to development 

and submission of the original plan. 

(b) A revision of a plan, or any portion 

thereof, shall not be considered part of 

an applicable plan until approved by 

the Administrator in accordance with 

this subpart. 

§ 60.29a Plan revisions by the 

Administrator. 

After notice and opportunity for 

public hearing in each affected State, 

the Administrator may revise any 

provision of an applicable federal plan 

if: 

(a) The provision was promulgated by 

the Administrator, and 

(b) The plan, as revised, will be 

consistent with the Act and with the 

requirements of this subpart. 

■ 7. Add subpart UUUUa to read as 

follows: 

Subpart—UUUUa Emission Guidelines for 

Greenhouse Gas Emissions and 

Compliance Times for Electric Utility 

Generating Units 

Introduction 

Sec. 

60.5700a What is the purpose of this 

subpart? 

60.5705a Which pollutants are regulated by 

this subpart? 

60.5710a Am I affected by this subpart? 

60.5715a What is the review and approval 

process for my plan? 

60.5720a What if I do not submit a plan or 

my plan is not approvable? 

60.5725a In lieu of a State plan submittal, 

are there other acceptable option(s) for a 

State to meet its CAA section 111(d) 

obligations? 

60.5730a Is there an approval process for a 

negative declaration letter? 

State Plan Requirements 

60.5735a What must I include in my 

federally enforceable State plan? 

60.5740a What must I include in my plan 

submittal? 

60.5745a What are the timing requirements 

for submitting my plan? 

60.5750a What schedules, performance 

periods, and compliance periods must I 

include in my plan? 

60.5755a What standards of performance 

must I include in my plan? 

60.5760a What is the procedure for revising 

my plan? 

60.5765a What must I do to meet my plan 

obligations? 

Applicablity of Plans to Affected EGUs 

60.5770a Does this subpart directly affect 

EGU owners or operators in my State? 

60.5775a What affected EGUs must I 

address in my State plan? 

60.5780a What EGUs are excluded from 

being affected EGUs? 

60.5785a What applicable monitoring, 

recordkeeping, and reporting 

requirements do I need to include in my 

plan for affected EGUs? 

Recordkeeping and Reporting Requirements 

60.5790a What are my recordkeeping 

requirements? 

60.5795a What are my reporting and 

notification requirements? 

60.5800a How do I submit information 

required by these Emission Guidelines to 

the EPA? 

Definitions 

60.5805a What definitions apply to this 

subpart? 


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Subpart—UUUUa Emission Guidelines 

for Greenhouse Gas Emissions and 

Compliance Times for Electric Utility 

Generating Units 

Introduction 

§ 60.5700a What is the purpose of this 

subpart? 

This subpart establishes emission 

guidelines and approval criteria for 

State plans that establish standards of 

performance limiting greenhouse gas 

(GHG) emissions from an affected steam 

generating unit. An affected steam 

generating unit for the purposes of this 

subpart, is referred to as an affected 

EGU. These emission guidelines are 

developed in accordance with section 

111(d) of the Clean Air Act and subpart 

Ba of this part. To the extent any 

requirement of this subpart is 

inconsistent with the requirements of 

subparts A or subpart Ba of this part, the 

requirements of this subpart will apply. 

§ 60.5705a Which pollutants are regulated 

by this subpart? 

(a) The pollutants regulated by this 

subpart are greenhouse gases. The 

emission guidelines for greenhouse 

gases established in this subpart are heat 

rate improvements which target 

achieving lower carbon dioxide (CO2) 

emission rates at affected EGUs. 

(b) PSD and Title V thresholds for 

greenhouse gases are set out in this 

paragraph (b). 

(1) For the purposes of 

§ 51.166(b)(49)(ii), with respect to GHG 

emissions from facilities, the ‘‘pollutant 

that is subject to the standard 

promulgated under section 111 of the 

Act’’ shall be considered to be the 

pollutant that otherwise is subject to 

regulation under the Act as defined in 

§ 51.166(b)(48) and in any State 

Implementation Plan (SIP) approved by 

the EPA that is interpreted to 

incorporate, or specifically incorporates, 

§ 51.166(b)(48) of this chapter. 

(2) For the purposes of 

§ 52.21(b)(50)(ii), with respect to GHG 

emissions from facilities regulated in 

the plan, the ‘‘pollutant that is subject 

to the standard promulgated under 

section 111 of the Act’’ shall be 

considered to be the pollutant that 

otherwise is subject to regulation under 

the Act as defined in § 52.21(b)(49) of 

this chapter. 

(3) For the purposes of § 70.2 of this 

chapter, with respect to greenhouse gas 

emissions from facilities regulated in 

the plan, the ‘‘pollutant that is subject 

to any standard promulgated under 

section 111 of the Act’’ shall be 

considered to be the pollutant that 

otherwise is ‘‘subject to regulation’’ as 

defined in § 70.2 of this chapter. 

(4) For the purposes of § 71.2, with 

respect to greenhouse gas emissions 

from facilities regulated in the plan, the 

‘‘pollutant that is subject to any 

standard promulgated under section 111 

of the Act’’ shall be considered to be the 

pollutant that otherwise is ‘‘subject to 

regulation’’ as defined in § 71.2 of this 

chapter. 

§ 60.5710a Am I affected by this subpart? 

If you are the Governor of a State in 

the contiguous United States with one 

or more affected EGUs that commenced 

construction on or before August 31, 

2018, you are subject to this action and 

you must submit a State plan to the U.S. 

Environmental Protection Agency (EPA) 

that implements the emission guidelines 

contained in this subpart. If you are the 

Governor of a State in the United States 

with no affected EGUs for which 

construction commenced on or before 

August 31, 2018, in your State, you 

must submit a negative declaration 

letter in place of the State plan. 

§ 60.5715a What is the review and 

approval process for my plan? 

The EPA will review your plan 

according to § 60.27a to approve or 

disapprove such plan or revision or 

each portion thereof. 

§ 60.5720a What if I do not submit a plan 

or my plan is not approvable? 

(a) If you do not submit an approvable 

plan the EPA will develop a Federal 

plan for your State according to 

§ 60.27a. The Federal plan will 

implement the emission guidelines 

contained in this subpart. Owners and 

operators of affected EGUs not covered 

by an approved plan must comply with 

a Federal plan implemented by the EPA 

for the State. 

(b) After a Federal plan has been 

implemented in your State, it will be 

withdrawn when your State submits, 

and the EPA approves, a plan. 

§ 60.5725a In lieu of a State plan submittal, 

are there other acceptable option(s) for a 

State to meet its CAA section 111(d) 

obligations? 

A State may meet its CAA section 

111(d) obligations only by submitting a 

State plan submittal or a negative 

declaration letter (if applicable). 

§ 60.5730a Is there an approval process 

for a negative declaration letter? 

The EPA has no formal review 

process for negative declaration letters. 

Once your negative declaration letter 

has been received, the EPA will place a 

copy in the public docket and publish 

a notice in the Federal Register. If, at a 

later date, an affected EGU for which 

construction commenced on or before 

August 31, 2018 is found in your State, 

you will be found to have failed to 

submit a final plan as required, and a 

Federal plan implementing the emission 

guidelines contained in this subpart, 

when promulgated by the EPA, will 

apply to that affected EGU until you 

submit, and the EPA approves, a final 

State plan. 

State Plan Requirements 

§ 60.5735a What must I include in my 

federally enforceable State plan? 

(a) You must include the components 

described in paragraphs (a)(1) through 

(4) of this section in your plan 

submittal. The final plan must meet the 

requirements of, and include the 

information required under, § 60.5740a. 

(1) Identification of affected EGUs. 

Consistent with § 60.25a(a), you must 

identify the affected EGUs covered by 

your plan and all affected EGUs in your 

State that meet the applicability criteria 

in § 60.5775a. In addition, you must 

include an inventory of CO2 emissions 

from the affected EGUs during the most 

recent calendar year for which data is 

available prior to the submission of the 

plan. 

(2) Standards of performance. You 

must provide a standard of performance 

for each affected EGU according to 

§ 60.5755a and compliance periods for 

each standard of performance according 

to § 60.5750a. In establishing a standard 

of performance, the state must evaluate 

all of the heat rate improvements 

described in § 60.5740a. 

(3) Identification of applicable 

monitoring, reporting, and 

recordkeeping requirements for each 

affected EGU. You must include in your 

plan all applicable monitoring, 

reporting and recordkeeping 

requirements for each affected EGU and 

the requirements must be consistent 

with or no less stringent than the 

requirements specified in § 60.5785a. 

(4) State reporting. Your plan must 

include a description of the process, 

contents, and schedule for State 

reporting to the EPA about plan 

implementation and progress, including 

information required under § 60.5795a. 

(b) You must follow the requirements 

of subpart Ba of this part and 

demonstrate that they were met in your 

State plan. 

§ 60.5740a What must I include in my plan 

submittal? 

(a) In addition to the components of 

the plan listed in § 60.5735a, a state 

plan submittal to the EPA must include 

the information in paragraphs (a)(1) 

through (8) of this section. This 

information must be submitted to the 

EPA as part of your plan submittal but 


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will not be codified as part of the 

federally enforceable plan upon 

approval by EPA. 

(1) You must include a summary of 

how you determined each standard of 

performance for each affected EGU 

according to § 60.5755a(a). You must 

include in the summary an evaluation of 

the applicability of each of the following 

heat rate improvements to each affected 

EGU: 

(i) Neural network/intelligent 

sootblowers 

(ii) Boiler feed pumps 

(iii) Air heater and duct leakage 

control 

(iv) Variable frequency drives 

(v) Blade path upgrades for steam 

turbines 

(vi) Redesign or replacement of 

economizer 

(vii) Improved operating and 

maintenance practices 

(2) In applying a standard of 

performance, if you consider remaining 

useful life and other factors for an 

affected EGU as provided in § 60.24a(e), 

you must include a summary of the 

application of the relevant factors in 

deriving a standard of performance. 

(3) You must include a demonstration 

that each affected EGU’s standard of 

performance is quantifiable, nonduplicative, permanent, verifiable, and 

enforceable according to § 60.5755a. 

(4) Your plan demonstration, if 

applicable, must include the 

information listed in paragraphs (a)(4)(i) 

through (v) of this section as applicable. 

(i) A summary of each affected EGU’s 

anticipated future operation 

characteristics, including: 

(A) Annual generation; 

(B) CO2 emissions; 

(C) Fuel use, fuel prices (when 

applicable), fuel carbon content; 

(D) Fixed and variable operations and 

maintenance costs (when applicable); 

(E) Heat rates; and 

(F) Electric generation capacity and 

capacity factors. 

(ii) A timeline for implementation of 

EGU-specific actions (if applicable). 

(iii) All wholesale electricity prices. 

(iv) A time period of analysis, which 

must extend through at least 2035. 

(v) A demonstration that each 

standard of performance included in 

your plan meets the requirements of 

§ 60.5755a. 

(5) Your plan submittal must include 

a timeline with all the programmatic 

milestone steps the State intends to take 

between the time of the State plan 

submittal and [date three years after the 

notice of availability of a final emission 

guideline is published in the Federal 

Register] to ensure the plan is effective 

as of [date plan takes effect]. 

(6) Your plan submittal must 

adequately demonstrate that your State 

has the legal authority (e.g., through 

regulations or legislation) and funding 

to implement and enforce each 

component of the State plan submittal, 

including federally enforceable 

standards of performance for affected 

EGUs. 

(7) Your plan submittal must include 

certification that a hearing required 

under § 60.23a(c)on the State plan was 

held, a list of witnesses and their 

organizational affiliations, if any, 

appearing at the hearing, and a brief 

written summary of each presentation or 

written submission, pursuant to the 

requirements of § 60.27a(f). 

(8) Your plan submittal must include 

supporting material for your plan 

including: 

(i) Materials demonstrating the State’s 

legal authority to implement and 

enforce each component of its plan, 

including standards of performance, 

pursuant to the requirements of 

§ 60.27a(f) and § 60.5740a(a)(6); 

(ii) Materials supporting calculations 

for affected EGU’s standards of 

performance according to § 60.5755a; 

and 

(iii) Any other materials necessary to 

support evaluation of the plan by the 

EPA. 

(b) You must submit your final plan 

to the EPA electronically according to 

§ 60.5800a. 

§ 60.5745a What are the timing 

requirements for submitting my plan? 

You must submit a plan with the 

information required under § 60.5740a 

by [date three years after the notice of 

availability of a final emission guideline 

is published in the Federal Register]. 

§ 60.5750a What schedules, performance 

periods, and compliance periods must I 

include in my plan? 

The standards of performance for 

affected EGUs regulated under the plan 

must include compliance periods. Any 

compliance period extending more than 

24 months from the date required for 

submittal of the plan must include 

legally enforceable increments of 

progress to achieve compliance for each 

designated facility or category of 

facilities. 

§ 60.5755a What standards of performance 

must I include in my plan? 

(a) You must set a standard of 

performance for each affected EGU 

within the state. 

(1) The standard of performance must 

be an emission performance rate relating 

mass of CO2 emitted per unit of energy 

(e.g. pounds of CO2 emitted per MWh). 

(2) In establishing any standard of 

performance, you must consider the 

applicability of each of the heat rate 

improvements included in § 60.5740a(1) 

to the affected EGU. 

(i) In applying a standard of 

performance to any affected EGU, you 

may consider the source-specific factors 

included in § 60.24(e). 

(ii) If you consider source-specific 

factors to apply a standard of 

performance, you must include a 

demonstration in your plan submission 

for how you considered such factors. 

(b) Standards of performance for 

affected EGUs included under your plan 

must be demonstrated to be 

quantifiable, verifiable, non-duplicative, 

permanent, and enforceable with 

respect to each affected EGU. The plan 

submittal must include the methods by 

which each standard of performance 

meets each of the requirements in 

paragraphs (c) through (f) of this section. 

(c) An affected EGU’s standard of 

performance is quantifiable if it can be 

reliably measured in a manner that can 

be replicated. 

(d) An affected EGU’s standard of 

performance is verifiable if adequate 

monitoring, recordkeeping and 

reporting requirements are in place to 

enable the State and the Administrator 

to independently evaluate, measure, and 

verify compliance with the standard of 

performance. 

(e) An affected EGU’s standard of 

performance is permanent if the 

standard of performance must be met for 

each compliance period, unless it is 

replaced by another standard of 

performance in an approved plan 

revision. 

(f) An affected EGU’s standard of 

performance is enforceable if: 

(1) A technically accurate limitation 

or requirement and the time period for 

the limitation or requirement are 

specified; 

(2) Compliance requirements are 

clearly defined; 

(3) The affected EGU responsible for 

compliance and liable for violations can 

be identified; 

(4) Each compliance activity or 

measure is enforceable as a practical 

matter; and 

(5) The Administrator, the State, and 

third parties maintain the ability to 

enforce against violations (including if 

an affected EGU does not meet its 

standard of performance based on its 

emissions) and secure appropriate 

corrective actions, in the case of the 

Administrator pursuant to CAA sections 

113(a)–(h), in the case of a State, 

pursuant to its plan, State law or CAA 

section 304, as applicable, and in the 


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case of third parties, pursuant to CAA 

section 304. 

§ 60.5760a What is the procedure for 

revising my plan? 

EPA-approved plans can be revised 

only with approval by the 

Administrator. The Administrator will 

approve a plan revision if it is 

satisfactory with respect to the 

applicable requirements of this subpart 

and any applicable requirements of 

subpart Ba of this part, including the 

requirements in § 60.5740a. If one (or 

more) of the elements of the plan set in 

§ 60.5735a require revision, a request 

must be submitted to the Administrator 

indicating the proposed revisions to the 

plan to ensure the CO2 emission 

performance are met. 

§ 60.5765a What must I do to meet my plan 

obligations? 

To meet your plan obligations, you 

must demonstrate that your affected 

EGUs are complying with their 

standards of performance as specified in 

§ 60.5755a. 

Applicability of Plans to Affected EGUs 

§ 60.5770a Does this subpart directly 

affect EGU owners or operators in my 

State? 

(a) This subpart does not directly 

affect EGU owners or operators in your 

State. However, affected EGU owners or 

operators must comply with the plan 

that a State develops to implement the 

emission guidelines contained in this 

subpart. 

(b) If a State does not submit a plan 

to implement and enforce the emission 

guidelines contained in this subpart by 

[date three years after the notice of 

availability of a final emission guideline 

is published in the Federal Register], or 

the date that EPA disapproves a final 

plan, the EPA will implement and 

enforce a Federal plan, as provided in 

§ 60.27a(c), applicable to each affected 

EGU within the State that commenced 

construction on or before January 8, 

2014. 

§ 60.5775a What affected EGUs must I 

address in my State plan? 

(a) The EGUs that must be addressed 

by your plan are any affected EGU that 

commenced construction on or before 

August 31, 2018. 

(b) An affected EGU is a steam 

generating unit that meets the relevant 

applicability conditions specified in 

paragraph (b)(1) through (2), as 

applicable, of this section except as 

provided in § 60.5780a. 

(1) Serves a generator connected to a 

utility power distribution system with a 

nameplate capacity greater than 25 MWnet (i.e., capable of selling greater than 

25 MW of electricity); 

(2) Has a base load rating (i.e., design 

heat input capacity) greater than 260 GJ/ 

hr (250 MMBtu/hr) heat input of fossil 

fuel (either alone or in combination 

with any other fuel). 

§ 60.5780a What EGUs are excluded from 

being affected EGUs? 

(a) An EGU that is excluded from 

being an affected EGU is: 

(1) An EGU that is subject to subpart 

TTTT of this part as a result of 

commencing construction, 

reconstruction or modification after the 

subpart TTTT applicability date; 

(2) A steam generating unit that is, 

and always has been, subject to a 

federally enforceable permit limiting 

annual net-electric sales to one-third or 

less of its potential electric output, or 

219,000 MWh or less; 

(3) A stationary combustion turbine 

that meets the definition of either a 

combined cycle or combined heat and 

power combustion turbine; 

(4) An IGCC unit; 

(5) A non-fossil unit (i.e., a unit that 

is capable of combusting 50 percent or 

more non-fossil fuel) that has always 

limited the use of fossil fuels to 10 

percent or less of the annual capacity 

factor or is subject to a federally 

enforceable permit limiting fossil fuel 

use to 10 percent or less of the annual 

capacity factor; 

(6) An EGU that is a combined heat 

and power unit that has always limited, 

or is subject to a federally enforceable 

permit limiting, annual net-electric sales 

to a utility distribution system to no 

more than the greater of either 219,000 

MWh or the product of the design 

efficiency and the potential electric 

output; 

(7) An EGU that serves a generator 

along with other steam generating 

unit(s), IGCC(s), or stationary 

combustion turbine(s) where the 

effective generation capacity 

(determined based on a prorated output 

of the base load rating of each steam 

generating unit, IGCC, or stationary 

combustion turbine) is 25 MW or less; 

(8) An EGU that is a municipal waste 

combustor unit that is subject to subpart 

Eb of this part; or 

(9) An EGU that is a commercial or 

industrial solid waste incineration unit 

that is subject to subpart CCCC of this 

part. 

(b) [Reserved] 

§ 60.5785a What applicable monitoring, 

recordkeeping, and reporting requirements 

do I need to include in my plan for affected 

EGUs? 

(a) Your plan must include 

monitoring, recordkeeping, and 

reporting requirements for affected 

EGUs. To satisfy this requirement, you 

have the option of either: 

(1) Specifying that sources must 

report emission and electricity 

generation data according to part 75 of 

this chapter; or 

(2) Describing an alternative 

monitoring, recordkeeping, and 

reporting program that includes 

specifications for the following program 

elements: 

(i) Monitoring plans that specify the 

monitoring methods, systems, and 

formulas that will be used to measure 

CO2 emissions; 

(ii) Monitoring methods to 

continuously and accurately measure all 

CO2 emissions, CO2 emission rates, and 

other data necessary to determine 

compliance or assure data quality; 

(iii) Quality assurance test 

requirements to ensure monitoring 

systems provide reliable and accurate 

data for assessing and verifying 

compliance; 

(iv) Recordkeeping requirements; 

(v) Electronic reporting procedures 

and systems; and 

(vi) Data validation procedures for 

ensuring data are complete and 

calculated consistent with program 

rules, including procedures for 

determining substitute data in instances 

where required data would otherwise be 

incomplete. 

(b) [Reserved] 

Recordkeeping and Reporting 

Requirements 

§ 60.5790a What are my recordkeeping 

requirements? 

(a) You must keep records of all 

information relied upon in support of 

any demonstration of plan components, 

plan requirements, supporting 

documentation, and the status of 

meeting the plan requirements defined 

in the plan for each interim step and the 

interim period. After [date plan takes 

effect], States must keep records of all 

information relied upon in support of 

any continued demonstration that the 

final CO2 emission performance rates or 

CO2 emissions goals are being achieved. 

(b) You must keep records of all data 

submitted by the owner or operator of 

each affected EGU that is used to 

determine compliance with each 

affected EGU emissions standard or 

requirements in an approved State plan, 

consistent with the affected EGU 

requirements listed in § 60.5785a. 

(c) If your State has a requirement for 

all hourly CO2 emissions and net 

generation information to be used to 

calculate compliance with an annual 

emissions standard for affected EGUs, 


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any information that is submitted by the 

owners or operators of affected EGUs to 

the EPA electronically pursuant to 

requirements in Part 75 meets the 

recordkeeping requirement of this 

section and you are not required to keep 

records of information that would be in 

duplicate of paragraph (b) of this 

section. 

(d) You must keep records at a 

minimum for 5 years from the date the 

record is used to determine compliance 

with a standard of performance or plan 

requirement. Each record must be in a 

form suitable and readily available for 

expeditious review. 

§ 60.5795a What are my reporting and 

notification requirements? 

You must submit an annual report as 

required under § 60.25a(e) and (f). 

§ 60.5800a How do I submit information 

required by these Emission Guidelines to 

the EPA? 

(a) You must submit to the EPA the 

information required by the emission 

guidelines in this subpart following the 

procedures in paragraphs (b) through (e) 

of this section. 

(b) All negative declarations, State 

plan submittals, supporting materials 

that are part of a State plan submittal, 

any plan revisions, and all State reports 

required to be submitted to the EPA by 

the State plan must be reported through 

EPA’s State Plan Electronic Collection 

System (SPeCS). SPeCS is a web 

accessible electronic system accessed at 

the EPA’s Central Data Exchange (CDX) 

(http://www.epa.gov/cdx/). States who 

claim that a State plan submittal or 

supporting documentation includes 

confidential business information (CBI) 

must submit that information on a 

compact disc, flash drive, or other 

commonly used electronic storage 

media to the EPA. The electronic media 

must be clearly marked as CBI and 

mailed to U.S. EPA/OAQPS/CORE CBI 

Office, Attention: State and Local 

Programs Group, MD C539–01, 4930 

Old Page Rd., Durham, NC 27703. 

(c) Only a submittal by the Governor 

or the Governor’s designee by an 

electronic submission through SPeCS 

shall be considered an official submittal 

to the EPA under this subpart. If the 

Governor wishes to designate another 

responsible official the authority to 

submit a State plan, the EPA must be 

notified via letter from the Governor 

prior to the [date three years after the 

notice of availability of a final emission 

guideline is published in the Federal 

Register], deadline for plan submittal so 

that the official will have the ability to 

submit a plan in the SPeCS. If the 

Governor has previously delegated 

authority to make CAA submittals on 

the Governor’s behalf, a State may 

submit documentation of the delegation 

in lieu of a letter from the Governor. The 

letter or documentation must identify 

the designee to whom authority is being 

designated and must include the name 

and contact information for the designee 

and also identify the State plan 

preparers who will need access to 

SPeCS. A State may also submit the 

names of the State plan preparers via a 

separate letter prior to the designation 

letter from the Governor in order to 

expedite the State plan administrative 

process. Required contact information 

for the designee and preparers includes 

the person’s title, organization, and 

email address. 

(d) The submission of the information 

by the authorized official must be in a 

non-editable format. In addition to the 

non-editable version all plan 

components designated as federally 

enforceable must also be submitted in 

an editable version. 

(e) You must provide the EPA with 

non-editable and editable copies of any 

submitted revision to existing approved 

federally enforceable plan components. 

The editable copy of any such submitted 

plan revision must indicate the changes 

made at the State level, if any, to the 

existing approved federally enforceable 

plan components, using a mechanism 

such as redline/strikethrough. These 

changes are not part of the State plan 

until formal approval by EPA. 

Definitions 

§ 60.5805a What definitions apply to this 

subpart? 

As used in this subpart, all terms not 

defined herein will have the meaning 

given them in the Clean Air Act and in 

subparts TTTT, A (General Provisions) 

and subpart Ba of this part. 

Affected electric generating unit or 

Affected EGU means a steam generating 

unit that meets the relevant 

applicability conditions in section 

§ 60.5775a, except as provided in 

§ 60.5780a. 

Air heater means a device that 

recovers heat from the flue gas for use 

in pre-heating the incoming combustion 

air and potentially for other uses such 

as coal drying. 

Annual capacity factor means the 

ratio between the actual heat input to an 

EGU during a calendar year and the 

potential heat input to the EGU had it 

been operated for 8,760 hours during a 

calendar year at the base load rating. 

Base load rating means the maximum 

amount of heat input (fuel) that an EGU 

can combust on a steady-state basis, as 

determined by the physical design and 

characteristics of the EGU at ISO 

conditions. 

Boiler feed pump (or boiler feedwater 

pump) means a device used to pump 

feedwater into a steam boiler at an EGU. 

The water may be either freshly 

supplied or returning condensate 

produced from condensing steam 

produced by the boiler. 

CO2 emission rate means for an 

affected EGU, the reported CO2 emission 

rate of an affected EGU used by an 

affected EGU to demonstrate 

compliance with its CO2 standard of 

performance. 

Combined heat and power unit or 

CHP unit, (also known as 

‘‘cogeneration’’) means an electric 

generating unit that uses a steamgenerating unit or stationary combustion 

turbine to simultaneously produce both 

electric (or mechanical) and useful 

thermal output from the same primary 

energy source. 

Compliance period means a discrete 

time period for an affected EGU to 

comply with a standard of performance. 

Economizer means a heat exchange 

device used to capture waste heat from 

boiler flue gas which is then used to 

heat the boiler feedwater. 

Fossil fuel means natural gas, 

petroleum, coal, and any form of solid 

fuel, liquid fuel, or gaseous fuel derived 

from such material to create useful heat. 

Integrated gasification combined 

cycle facility or IGCC means a combined 

cycle facility that is designed to burn 

fuels containing 50 percent (by heat 

input) or more solid-derived fuel not 

meeting the definition of natural gas 

plus any integrated equipment that 

provides electricity or useful thermal 

output to either the affected facility or 

auxiliary equipment. The Administrator 

may waive the 50 percent solid-derived 

fuel requirement during periods of the 

gasification system construction, startup 

and commissioning, shutdown, or 

repair. No solid fuel is directly burned 

in the unit during operation. 

Intelligent sootblower means an 

automated system that use process 

measurements to monitor the heat 

transfer performance and strategically 

allocate steam to specific areas to 

remove ash buildup at a steam 

generating unit. 

ISO conditions means 288 Kelvin (15 

°C), 60 percent relative humidity and 

101.3 kilopascals pressure. 

Nameplate capacity means, starting 

from the initial installation, the 

maximum electrical generating output 

that a generator, prime mover, or other 

electric power production equipment 

under specific conditions designated by 

the manufacturer is capable of 

producing (in MWe, rounded to the 


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44812 Federal Register / Vol. 83, No. 170 / Friday, August 31, 2018 / Proposed Rules 

nearest tenth) on a steady-state basis 

and during continuous operation (when 

not restricted by seasonal or other 

deratings) as of such installation as 

specified by the manufacturer of the 

equipment, or starting from the 

completion of any subsequent physical 

change resulting in an increase in the 

maximum electrical generating output 

that the equipment is capable of 

producing on a steady-state basis and 

during continuous operation (when not 

restricted by seasonal or other 

deratings), such increased maximum 

amount (in MWe, rounded to the nearest 

tenth) as of such completion as 

specified by the person conducting the 

physical change. 

Natural gas means a fluid mixture of 

hydrocarbons (e.g., methane, ethane, or 

propane), composed of at least 70 

percent methane by volume or that has 

a gross calorific value between 35 and 

41 megajoules (MJ) per dry standard 

cubic meter (950 and 1,100 Btu per dry 

standard cubic foot), that maintains a 

gaseous State under ISO conditions. In 

addition, natural gas contains 20.0 

grains or less of total sulfur per 100 

standard cubic feet. Finally, natural gas 

does not include the following gaseous 

fuels: landfill gas, digester gas, refinery 

gas, sour gas, blast furnace gas, coalderived gas, producer gas, coke oven 

gas, or any gaseous fuel produced in a 

process which might result in highly 

variable sulfur content or heating value. 

Net electric output means the amount 

of gross generation the generator(s) 

produce (including, but not limited to, 

output from steam turbine(s), 

combustion turbine(s), and gas 

expander(s)), as measured at the 

generator terminals, less the electricity 

used to operate the plant (i.e., auxiliary 

loads); such uses include fuel handling 

equipment, pumps, fans, pollution 

control equipment, other electricity 

needs, and transformer losses as 

measured at the transmission side of the 

step up transformer (e.g., the point of 

sale). 

Net energy output means: 

(1) The net electric or mechanical 

output from the affected facility, plus 

100 percent of the useful thermal output 

measured relative to SATP conditions 

that is not used to generate additional 

electric or mechanical output or to 

enhance the performance of the unit 

(e.g., steam delivered to an industrial 

process for a heating application). 

(2) For combined heat and power 

facilities where at least 20.0 percent of 

the total gross or net energy output 

consists of electric or direct mechanical 

output and at least 20.0 percent of the 

total gross or net energy output consists 

of useful thermal output on a 12- 

operating month rolling average basis, 

the net electric or mechanical output 

from the affected EGU divided by 0.95, 

plus 100 percent of the useful thermal 

output; (e.g., steam delivered to an 

industrial process for a heating 

application). 

Neural network means a computer 

model that can be used to optimize 

combustion conditions, steam 

temperatures, and air pollution at steam 

generating unit. 

Programmatic milestone means the 

implementation of measures necessary 

for plan progress, including specific 

dates associated with such 

implementation. Prior to [date plan 

takes effect], programmatic milestones 

are applicable to all state plan 

approaches and measures. 

Standard ambient temperature and 

pressure (SATP) conditions means 

298.15 Kelvin (25 °C, 77 °F)) and 100.0 

kilopascals (14.504 psi, 0.987 atm) 

pressure. The enthalpy of water at SATP 

conditions is 50 Btu/lb. 

State agent means an entity acting on 

behalf of the State, with the legal 

authority of the State. 

Stationary combustion turbine means 

all equipment, including but not limited 

to the turbine engine, the fuel, air, 

lubrication and exhaust gas systems, 

control systems (except emissions 

control equipment), heat recovery 

system, fuel compressor, heater, and/or 

pump, post-combustion emissions 

control technology, and any ancillary 

components and sub-components 

comprising any simple cycle stationary 

combustion turbine, any combined 

cycle combustion turbine, and any 

combined heat and power combustion 

turbine based system plus any 

integrated equipment that provides 

electricity or useful thermal output to 

the combustion turbine engine, heat 

recovery system or auxiliary equipment. 

Stationary means that the combustion 

turbine is not self-propelled or intended 

to be propelled while performing its 

function. It may, however, be mounted 

on a vehicle for portability. If a 

stationary combustion turbine burns any 

solid fuel directly it is considered a 

steam generating unit. 

Steam generating unit means any 

furnace, boiler, or other device used for 

combusting fuel and producing steam 

(nuclear steam generators are not 

included) plus any integrated 

equipment that provides electricity or 

useful thermal output to the affected 

facility or auxiliary equipment. 

Useful thermal output means the 

thermal energy made available for use in 

any heating application (e.g., steam 

delivered to an industrial process for a 

heating application, including thermal 

cooling applications) that is not used for 

electric generation, mechanical output 

at the affected EGU, to directly enhance 

the performance of the affected EGU 

(e.g., economizer output is not useful 

thermal output, but thermal energy used 

to reduce fuel moisture is considered 

useful thermal output), or to supply 

energy to a pollution control device at 

the affected EGU. Useful thermal output 

for affected EGU(s) with no condensate 

return (or other thermal energy input to 

the affected EGU(s)) or where measuring 

the energy in the condensate (or other 

thermal energy input to the affected 

EGU(s)) would not meaningfully impact 

the emission rate calculation is 

measured against the energy in the 

thermal output at SATP conditions. 

Affected EGU(s) with meaningful energy 

in the condensate return (or other 

thermal energy input to the affected 

EGU) must measure the energy in the 

condensate and subtract that energy 

relative to SATP conditions from the 

measured thermal output. 

Valid data means quality-assured data 

generated by continuous monitoring 

systems that are installed, operated, and 

maintained according to part 75 of this 

chapter. For CEMS, the initial 

certification requirements in § 75.20 of 

this chapter and appendix A to part 75 

of this chapter must be met before 

quality-assured data are reported under 

this subpart; for on-going quality 

assurance, the daily, quarterly, and 

semiannual/annual test requirements in 

sections 2.1, 2.2, and 2.3 of appendix B 

to part 75 of this chapter must be met 

and the data validation criteria in 

sections 2.1.5, 2.2.3, and 2.3.2 of 

appendix B to part 75 of this chapter 

apply. For fuel flow meters, the initial 

certification requirements in section 

2.1.5 of appendix D to part 75 of this 

chapter must be met before qualityassured data are reported under this 

subpart (except for qualifying 

commercial billing meters under section 

2.1.4.2 of appendix D), and for on-going 

quality assurance, the provisions in 

section 2.1.6 of appendix D to part 75 

of this chapter apply (except for 

qualifying commercial billing meters). 


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Variable frequency drive means an 

adjustable-speed drive used on induced 

draft fans and boiler feed pumps to 

control motor speed and torque by 

varying motor input frequency and 

voltage. 

Waste-to-Energy means a process or 

unit (e.g., solid waste incineration unit) 

that recovers energy from the 

conversion or combustion of waste 

stream materials, such as municipal 

solid waste, to generate electricity and 

/or heat. 

[FR Doc. 2018–18755 Filed 8–30–18; 8:45 am] 

BILLING CODE 6560–50–P 


daltland on DSKBBV9HB2PROD with PROPOSALS2