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During Review***

EO12866_CPP Federal Plan 2060 AS47 NPRM_2015072720150731

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 62

[EPA-HQ-OAR-2015-0199; FRL_XXXX-X]

RIN 2060-AS47

Federal Plan Requirements for Greenhouse Gas Emissions from 

Electric Utility Generating Units Constructed on or Before 

January 8, 2014; Model Trading Rules; Amendments to Framework 

Regulations

AGENCY: Environmental Protection Agency.

ACTION: Proposed Rule.

SUMMARY: In this action, the Environmental Protection Agency 

(EPA) is proposing a federal plan to implement the greenhouse 

gas (GHG) emission guidelines (EGs) for existing fossil fuelfired electric generating units (EGUs) under the Clean Air Act 

(CAA). The EGs were proposed in June 2014 and finalized on 

[&&&]August 3, 2015 as the Carbon Pollution Emission Guidelines 

for Existing Stationary Sources: Electric Utility Generating 

Units (also known as the Clean Power Plan or EGs). This proposal 

presents two approaches to a federal plan for states and other 

jurisdictions that do not adopt and submit to the EPA in a 

timely manner an approvable plan to the EPA: a rate-based 
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emission trading program and a mass-based emission trading 

program. These proposals also constitute proposed model trading 

rules that states can adopt or tailor for implementation of the 

final EGs. The federal plan is an important measure to ensure 

that congressionally mandated emission standards under the 

authority of the CAA are implemented. The proposed federal plan 

is related to but separate from the final EGs. The final EGs 

establish the best system of emission reduction (BSER) for 

applicable fossil fuel-fired EGUs in the form of a standard of 

&&&carbon dioxide (CO2) emission performance rate for steam-fired 

EGUs and a standard of &&&CO2 emission performance rate for 

natural gas-fired combined cycle units, and provide guidance and 

criteria for the development of approvable state plans. The 

purpose of the proposed federal plan is to establish 

requirements directly applicable to a state’s affected EGUs that 

meet these emission performance levels, or the BSERequivalent 

statewide goal, in order to achieve reductions in carbon dioxide 

(CO2) emissions in the case where a state or other jurisdiction 

does not submit an approvable plan. These CO2 reductions laid 

outThe stringency of the emission performance levels established

in the final EGs will be equivalentthe same whether implemented 

through a state plan or a federal plan. The EPA is also 

proposing enhancements to the CAA section 111(d) framework 
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regulations related to the process and timing for state plan 

submissions and EPA actions. The EPA intends to finalize both 

the rate-based and mass-based model trading rules in summer

2016.

DATES: Comments. Comments must be received on or before [insert 

date 4590 days after date of publication in the Federal 

Register]. 

Public Hearing. The EPA will be holding XXX [insert number of 

hearings here] public hearings on the proposed federal plan. The 

hearings will be held to accept oral comments on the proposed 

federal plan. The hearings will be held on XXX, 2015, in XXX, 

XXX, 2015, in XXX, and XXX, 2015, in XXX.[insert number, days of 

and locations of hearings here]. The hearings will begin at 9:00 

a.m. (local time) and will conclude at 8:00 p.m. (local time).

ADDRESSES: Submit your comments on the federal plan requirements 

proposed rule, identified by Docket ID No. EPA-HQ-OAR-2015-0199, 

by one of the following methods:

• Federal Rulemaking Portal http://www.regulations.gov: 

Follow the online instructions for submitting 

comments.

• Email: Send your comments via electronic mail to Aand-R-Docket@epa.gov, Attention Docket ID No. EPA-HQOAR-2015-0199.

• Facsimile: Fax your comments to (202) 566-9744, 

Attention Docket ID No. EPA-HQ-OAR-2015-0199.

• Mail: Send your comments to: EPA Docket Center 

(EPA/DC), Environmental Protection Agency, EPA Docket 

Center (EPA/DC), Mailcode: 28221T, 1200 Pennsylvania 
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Ave., NW, Washington, DC 20460, Attention Docket ID 

No. EPA-HQ-OAR-2015-0199. We request that a separate 

copy also be sent to the contact person identified 

below (see FOR FURTHER INFORMATION CONTACT). In 

addition, please mail a copy of your comments on the 

information collection provisions to the Office of 

Information and Regulatory Affairs, Office of 

Management and Budget, Attn: Desk Officer for EPA, 725 

17th Street NW., Washington, DC 20503.

• Hand Delivery: Deliver your comments to: EPA Docket 

Center (EPA/DC),, Room 3334, EPA WJC West Building, 

Room 3334, 1301 Constitution Ave., NW, Washington, DC, 

20004, Attention Docket ID No. EPA-HQ-OAR-2015-0199. 

Such deliveries are accepted only during the Docket’s 

normal hours of operation (8:30 a.m. to 4:30 p.m., 

Monday through Friday, excluding legal holidays) and 

special arrangements should be made for deliveries of 

boxed information.

Instructions: Direct your comments on the federal plan

requirements proposed rule to Docket ID No. EPA-HQ-OAR-2015-

0199. The EPA’s policy is that all comments received will be 

included in the public docket and may be made available online 

at http://www.regulations.gov, including any personal 

information provided, unless the comment includes information 

claimed to be confidential business information (CBI) or other 

information whose disclosure is restricted by statute. Do not 

submit information that you consider to be CBI or otherwise 

protected through http://www.regulations.gov or email. The 

http://www.regulations.gov Web site is an “anonymous access” 

system, which means the EPA will not know your identity or 

contact information unless you provide it in the body of your 
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comment. If you send an email comment directly to the EPA 

without going through http://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, 

the EPA recommends that you include your name and other contact 

information in the body of your comment and with any disk or 

CD-ROM you submit. If the EPA cannot read your comment due to 

technical difficulties and cannot contact you for clarification, 

the EPA may not be able to consider your comment. Electronic 

files should avoid the use of special characters, any form of 

encryption and be free of any defects or viruses.

Public Hearing: XXX [insert number of hearings hearhere] public 

hearings will be held to accept oral comments on the proposed 

federal plan. The hearings will be held on XXX, 2015, in XXX, 

XXX, 2015, in XXX, and XXX, 2015, in XXX.[insert number of, 

dates and locations of hearings here]. The hearings will begin 

at 9:00 a.m. (local time) and will conclude at 8:00 p.m. (local 

time). There will be a lunch break from 12:00 p.m. to 1:00 p.m. 

and a dinner break from 5:00 p.m. to 6:00 p.m. To register for 

theto speak at a hearing, please use the online registration 

form available at.: http://www.epa.gov/cleanpowerplan. For 

questions regarding registration, please contact XXXX[insert 
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name] at (919) 541–XXXX.–[insert number]. The last day to preregister to speak at the hearinghearings will be XXX,[insert 

date], 2015. Additionally, requests to speak will be taken the 

day of theeach hearing at the hearing registration desk, 

although preferences on speaking times may not be able to be 

fulfilled. Please note that registration requests received 

before theeach hearing will be confirmed by the EPA via email. 

We cannot guarantee that we can accommodate all timing requests 

and will provide requestors with the next available speaking 

time, in the event that theretheir requested time is taken. 

Please note that in the time outlined in the confirmation email 

received will be the time the one will be scheduled to speak at. 

Again, depending on the flow of the day, times may 

varyfluctuate. If you require the service of a translator or 

special accommodations such as audio description, we ask that 

you pre-register for the hearinghearings by XXX,[insert date],

2015, as we may not be able to arrange such accommodations 

without advance notice. Please note that any updates made to any 

aspect of the hearings will be posted online at 

http://.://www.epa.gov/cleanpowerplan. While the EPA expects the 

hearinghearings to go forward as set forth above, we ask that 

you monitor our Web site or contact XXXX[insert name] at (919) 

541–XXXX–[insert number] to determine if there are any updates 
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to the information on the hearings. The EPA does not intend to 

publish a notice in the Federal Register announcing any such 

updates. The hearinghearings will provide interested parties the 

opportunity to present data, views, or arguments concerning the 

proposed action. The EPA will make every effort to accommodate 

all speakers who arrive and register. The EPA may ask clarifying 

questions during the oral presentations, but will not respond to 

the presentations at that time. Written statements and 

supporting information submitted during the comment period will 

be considered with the same weight as oral comments and 

supporting information presented at the public hearing. Verbatim 

transcripts of the hearing and written statements will be 

included in the docket for the rulemaking. The EPA plans for the 

hearinghearings to run on schedule; however, due to on-site 

schedule fluctuations, actual speaking times may shift 

slightly.

Because these hearings are being held at United States (U.S..)

government facilities, individuals planning to attend the hearing 

should be prepared to show valid picture identification to the 

security staff in order to gain access to the meeting room. Please 

note that the REAL ID Act, passed by Congress in 2005, established 

new requirements for entering federal facilities. If your driver’s 

license is issued by Alaska, American Samoa, Arizona, Kentucky, 
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Louisiana, Maine, Massachusetts, Minnesota, Montana, New York, 

Oklahoma, or the state of Washington, you must present an 

additional form of identification to enter the federal building. 

Acceptable alternative forms of identification include: Federal 

employee badges, passports, enhanced driver’s licenses, and 

military identification cards. In addition, you will need to obtain 

a property pass for any personal belongings you bring with you. 

Upon leaving the building, you will be required to return this 

property pass to the security desk. No large signs will be allowed 

in the building, cameras may only be used outside of the building,

and demonstrations will not be allowed on federal property for 

security reasons. 

Attendees will be asked to go through metal detectors. To 

help facilitate this process, please be advised that you will be 

asked to remove all items from all pockets and place in provided 

bins for screening; remove laptops, phones, or other electronic 

devices from their carrying case and place in provided bins for

screening; avoid shoes with metal shanks, toe guards, or supports 

as a part of their construction; remove any metal belts, metal 

belt buckles, large jewelry, watches; and follow the instructions 

of the guard if identified for secondary screening. Additionally, 

no weapons (e.g., pocket knives) or drugs or drug paraphernalia 

(e.g., marijuana) will be allowed in the building. We recommend 
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that you arrive 20 minutes in advance of your speaking time to 

allow time to go through security and to check in with the 

registration desk.

Docket: The EPA has established a docket for this action under 

Docket ID No. EPA-HQ-OAR-2015-0199. The EPA has previously 

established a docket for the January 8, 2014, Clean Power Plan 

proposal under Docket ID No. EPA-HQ-OAR-2009-0559. All documents 

in the docket are listed in the http://www.regulations.gov

index. Although listed in the index, some information is not 

publicly available, e.g., CBI or other information whose 

disclosure is restricted by statute. Certain other material, 

such as copyrighted material, will be publicly available only in 

hard copy form. Publicly available docket materials are 

available either electronically at http://www.regulations.gov or 

in hard copy at the EPA Docket Center EPA/DC, EPA WJC West 

Building, Room 3334, 1301 Constitution Ave., NW, Washington, DC. 

The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., 

Monday through Friday, excluding 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.

FOR FURTHER INFORMATION CONTACT: Ms. Toni Jones, Fuels and 

Incineration Group, Sector Policies and Programs Division 

(E143-05), Environmental Protection Agency, Research Triangle 
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Park, North Carolina 27711; telephone number: (919) 541-0316; 

fax number: (919) 541-3470; email address: jones.toni@epa.gov.

SUPPLEMENTARY INFORMATION: 

Acronyms and Abbreviations. The following acronyms and 

abbreviations are used in this document.

AG Attorney General

ANSI American National Standards Institute

ASME American Society of Mechanical Engineers

ASTM American Society of Testing and Materials

ARP Acid Rain Program

BSER Best system of emission reduction

CAA Clean Air Act

CAIR Clean Air Interstate Rule

CARB California Air Resources Board

CBI Confidential Business Information

CDX Central Data Exchange

CEMS Continuous emissions monitoring system

CFCs Chlorofluorocarbons

CISWI Commercial Industrial Solid Waste Incinerators

CFR Code of Federal Regulations

CAIR Clean Air Interstate Rule

CHP Combined heat and power

CO2 Carbon dioxide

CO2 Carbon dioxide equivalent

CSAPR Cross-state Air Pollution Rule

EGDOE Department of Energy

EE Energy efficiency

EGs Emission Guidelines

eGRID Emissions & Generation Resource Integrated Database

EGU Electric generating unit

EIA Energy Information Administration
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EJ Environmental justice

EM&V Evaluation, measurement, and verification

EPA Environmental Protection Agency

EO Executive Order

FERC Federal Energy Regulatory Commission

FIP Federal implementation plan

FR Federal Register

GHG Greenhouse gas

GHGRP Greenhouse Gas Reporting Program

GJ/h Gigajoule per hour

HAP Hazardous air pollutants

ICR Information collection request

IGCC Integrated gasification combined cycle unit

IPM Integrated Planning Model

IPCC Intergovernmental Panel on Climate Change

ISO/RTO Independent System Operator/Regional Transmission 

Organizationlbs Pounds

LML Lowest measured PM2.5 levels

MATS Mercury and Air Toxics Standards

M&V Measurement and verification

MMBtu/h Million British Thermal units per hour

MSW Municipal solid waste

MW Megawatts

MWh Megawatt-hours

NAAQS National Ambient Air Quality Standards

NAICS North American Industrial Classification System

NEEDS NERC North American Electric Reliability Corporation

NSPS New source performance standards

NSR New Source Review

NTTAA National Electric Energy Data System Technology 

Transfer and Advancement Act

NTAA National Tribal Air Association

NOX Nitrogen oxides

OAP Office of Atmospheric Programs
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OAQPS Office of Air Quality Planning and Standards

PPA Power Purchase Agreement

PRA Paperwork Reduction Act

PV Photovoltaics

PUC Public Utility Commission

RE Renewable energy

REC Renewable Energy Certificate

RFA Regulatory Flexibility Act

RGGI Regional Greenhouse Gas Initiative

SBA Small Business Administration

RIA Regulatory impact analysis

SCT Stationary combustion turbine

SGU Steam generating unit

SIP State implementation plan

SO2 Sulfur dioxide

TSD Technical support document

The Court U.S. Court of Appeals for the District of Columbia 

Circuit

TTN Technology Transfer Network

UMRA Unfunded Mandates Reform Act of 1995

UNFCCC United Nations Framework Convention on Climate Change

U.S. United States

WWW WorldwideWorld Wide Web

Organization of This Document. The following outline is provided 

to aid in locating information in this preamble.

I. General Information

A. Executive Summary

B. Organization and Approach for this Proposed Rule

C. Who Does the Proposed Action Apply to?

D. What Should I Consider as I Prepare my Comments?

II. Background Information

A. What is the Regulatory Development Background for this 
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Proposed Rule?

B. What is the Purpose of this Proposed Rule?

C. Legal Authority

D. Timing of EPA Actions on the Model Trading Rules, Federal 

Plan, and other Proposed Actions

E. Use of the Model Trading Rule as a Backstop

III. Federal Plan Structure to Achieve Reductions 

A. Overview

B. Inventory of Emissions

C. Affected EGUs

D. Compliance Schedule

E. Addressing Reliability Concerns

F. Worker Certification

G. Remaining Useful Lives and Potential for “Stranded Assets”

H. Implications for Other EPA Programs and Rules

I. Administrative Appeals Process

J. Consistency of Program Structure with Clean Air Act Authority

IV. Rate-based Implementation Approach 

A. Overview

B. Rate Goals

C. Crediting Mechanism

D. ERC Tracking and Compliance Operations

E. Federal Plan and State Plan Interactions

V. Mass-based Implementation Approach 

A. Trading Program Overview 

B. Statewide Mass-based Emissions Goals

C. Compliance Timing and Allowance Banking

D. Initial Distribution of Allowances

E. State-determined Allowance Distribution

F. Treatment of States Entering or Exiting the Trading Program

G. Allowance Tracking, Compliance Operations, and Penalties

H. Emissions Monitoring and Reporting Requirements

VI. Implementation of the Federal Plan and Delegation

A. Delegation of the Federal Plan and Retained Authorities

B. Mechanisms for Transferring Authority
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C. Implementing Authority

D. Necessary or Appropriate Finding for Affected EGUs in Indian 

Country

VII. Amendments to Process for Submittal and Approval of State 

Plans and EPA Actions

A. Partial Approvals/Disapprovals

B. Conditional Approvals

C. Calls for Plan Revisions

D. Completeness Criteria

E. Update to Deadlines for EPA Actions

F. Proposed Interpretation regarding Existing Sources that 

Modify or Reconstruct

G. Separate Finalization of these Changes

VIII. Impacts of this Action

A. Endangered Species Act

B. What are the Air Impacts? 

C. What are the Energy Impacts? 

D. What are the Compliance Costs?

E. What are the Economic and Employment Impacts? 

F. What are the Benefits of the Proposed Action? 

IX. Community and Environmental Justice Considerations

A. Proximity Analysis

B. Community Engagement in This Rulemaking Process

C. Providing Communities with Access to Additional Resources

D. Federal Programs and Resources Available to Communities

E. Co-Pollutants

F. Assessing Impacts of Federal Plan Implementation

G. The EPA’s Continued Engagement

X. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and 

Executive Order 13563: Improving Regulation and Regulatory 

Review 

B. Paperwork Reduction Act (PRA)

C. Regulatory Flexibility Act (RFA)

D. Unfunded Mandates Reform Act (UMRA)
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E. Executive Order 13132: Federalism

F. Executive Order 13175: Consultation and Coordination with 

Indian Tribal Governments

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks

H. Executive Order 13211: Actions That Significantly Affect 

Energy Supply, Distribution, or Use 

I. National Technology Transfer and Advancement Act (NTTAA)

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations

I. General Information

A. Executive Summary 

In the Clean Air ActCAA, Congress created a partnership 

between the EPA and the states. Under section 111(d) of the 

Clean Air Act (CAA),, the EPA establishes emission performance 

levels based on its determination of the best system of emission 

reduction (BSER) for existing sources of air pollution and 

provides guidelines for state plans to apply standards of 

performance to their sources that meet the BSER level of 

performance. The EPA has promulgated these EGs under CAA section 

111(d), which sets source-level CO2 emission performance rates 

for the electric generating units (EGUs) at certain large fossil 

fuel-fired power plants (“affected EGUs”), which the states then 

apply to their sources in state plans. The EGsthrough 

implementation of state plans. At this point, the responsibility 
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shifts to the states who can submit plans to achieve these 

emission performance levels for EPA approval, or initial 

submittals, by September 6, 2016. The amount of reductions in CO2

that the EPA determined to be achievable for these sources is 

based on its determination of what constitutes the BSER. This 

determination is finalized in the EGs, which are designed to 

maximize the flexibility of both states and affected EGUs in 

meeting CO2 emissions performance rates. While states may impose 

the emission rates directly on their affected EGUs, states also 

have the option of submitting more tailored plans that meet

state-specific emissions goals. The EGs also provide flexibility 

by allowing for emissions trading and multi-state compliance 

options. The amount of reductions in CO2 that the EPA determined 

to be achievable for these sources was based on its 

determination of what constituted the best system of emission 

reduction (the BSER). This determination was finalized in the 

EGs. 

At this point the responsibility shifts to the states, who

can submit plans to achieve these emission performance levels

for EPA approval, or initial plan submittals, by August 31, 

2016. While it has been the EPA’s longstanding view that the 

statute identifies states as the preferred implementers of CAA

programs, the agency makes clear in the EGs that states cannot 
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and will not be penalized for failing to participate in this 

program. However, if a state does not submit an approvable plan 

under section 111(d) of the CAA, the EPA will develop, 

implement, and enforce a federal plan to reduce CO2 from the 

fossil fuel-fired power plants in that state. This is wholly 

consistent with the “cooperative federalism” structure of the 

CAA and many of our nation’s other environmental laws. In 

addition, we have heard from states and other stakeholders that 

it would be helpful for the agency to present model designs for 

state plans, and a federal plan would be an appropriate means of 

doing that. 

Accordingly, the EPA proposes a federal plan under section 

111(d) of the CAA for the control of CO2, a greenhouse gasGHG

pollutant, from certain large emitting fossil-fuel fired power 

plants, in the event that some states do not adopt their own 

plans. Specifically, the EPA is proposing approaches in the form 

of mass- and rate-based trading options that provide flexibility 

in implementing emission standards for a state’s affected EGUs.

Both proposed approaches to the federal plan would require

affected EGUs to meet emission standards set using the CO2

emission performance rates in the EGs. The federal plan will 

achieve the same levels of emissions performance as required of 

state plans under the EGs. The EPA will only promulgate a final 
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federal plan for the affected EGUs in states that the EPA 

determines did not submit an approvable plan.

At the same time, these two proposed options offer states 

model trading rules that the states can follow in developing 

their own plans in order to capitalize on the flexibility built 

into the final EGs. Thus, this noticedocument proposes four 

discrete actions: (1) A rate-based federal plan for each state 

with affected EGUs; (2) a mass-based federal plan for each state 

with affected EGUs; (3) a rate-based model trading rule for 

potential use by any state; and (4) a mass-based model trading 

rule for potential use by any state. The regulatory text of each 

federal plan and the corresponding model trading rule is 

identical, except as indicated otherwise within the text of the 

model rule (for instance, the EPA is providing model rule text 

for states to use related to the crediting of a broader set of

clean energy resources than is being proposed in the federal 

plan).

The EPA intends to finalize both the rate-based and massbased model trading rules in summer 2016. The EPA will only 

finalize a federal plan for a given state in the event that the 

state does not submit an approvable plan by the deadlines 

specified in the final EGs and the EPA takes action finding that 

the state has failed to submit a plan, or disapproving a 
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submitted plan because it does not meet the requirements of the 

EGs.1 Indeed, states may simply choose to accept a federal plan 

for their sources rather than undertake the development of a 

plan of their own by not submitting a state plan. Under this

proposed rule, a federal plan promulgated for a particular state 

would take the form of either the mass-based model trading rule 

or the rate-based model trading rule. The EPA currently intends 

to finalize a single approach (i.e., either the mass-based or 

rate-based approach) for every state in which it promulgates a

federal plan, given the benefits of a broad trading program, as 

discussed in the following section of this preamble... We invite 

comment on which approach, i.e., either mass-based or rate-based

trading, should be selected if we opt to finalize a single 

 

1 For simplicity, at times this document may refer to the coproposed federal plans as “the federal plan.” (It may refer to the 

model trading rules in the singular as well.) Even though the 

singular is used, this term is meant to encompass both the ratebased approach and the mass-based approach. The use of the singular 

when referring to this proposed federal plan also is intended to 

encompass all state-specific federal plans. In other words, the 

EPA intends to finalize “the federal plan” as a series of statespecific “federal plans.” This is consistent with the agency’s 

prior practice in other multi-state trading programs such as the 

NOx Budget Trading Program, the Clean Air Interstate Rule (CAIR), 

and the Cross-State Air Pollution Rule (CSAPR), where a single 

rule promulgated multiple FIPs. 
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approach.

It is the EPA’s intention to give the states as much

opportunity as possible to set their own course for carrying out 

the EGs. Even where a federal plan is put in place for a 

particular state, that state will still be able to submit a 

plan, which, upon approval, will allow the state and its sources 

to exit the federal plan. In addition, as discussed in section 

VI.A of this preamble, states may take delegation of 

administrative aspects of the federal plan in order to become 

the primary implementers. And as discussed in sections V.E and 

VII.A of this preamble, states may submit partial state plans in 

order to take over the implementation of a portion of a federal 

plan. For instance, in a mass-based trading program, the agency 

proposes to allow states to submit partial state plans to 

replace the federal plan allowance-distribution provisions with 

their own allowance-distribution provisions, similar to the 

approach we have taken in prior trading programs. Finally, even 

in states in which the affected EGUs are operating under a 

federal plan, the agency recognizes that states may adopt 

complementary measures outside of CAA programming to facilitate 

compliance and lower costs that could benefit power generators 

and consumers, directly or indirectly.

A state program that adheres to the model trading rule 
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provisions specified in this rulemaking would be presumptively 

approvable. States may submit means of meeting the EGs

requirements that differ from the model trading rule provisions, 

so long as the state demonstrates to the EPA’s satisfaction in 

the state plan submittal that such alternative means of 

addressing requirements are at least as stringent as the 

presumptively approvable approach described here.2 Additionally, 

there are stand-alone portions of the model trading rules, such 

as the evaluation, measurement, and verification (EM&V)

procedures, that would be approvable even if a state adopted an 

approach that differs from the federal plan. The model trading

rules servesserve as a mechanism to createfacilitate larger 

trading markets since consistency with the federal plan allows 

trading across both the state and federal programs. The EPA 

expects a larger trading region is likely to result in lower 

overall costs. These and other aspects of the model trading 

rules and federal plan provide additional support for this rule 

 

2 For example, in the context of a mass- or rate-based trading 

program, a state may submit a plan with alternative components 

other than those described, so long as the program includes each 

of the requirements and the state satisfactorily demonstrates in 

the state plan submittal that such alternative means of addressing 

the requirements are as stringent as the presumptively approvable 

approach as described, and therefore provide for the 

implementation of the state plan’s emission standards.
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as proposed. Thus, the proposed rule would ensure that 

congressionally mandated emission standards under authority of 

section 111 of the CAA are implemented, either by the states in 

the first instance, or by the EPA where needed.

The agency is proposing a finding that it is necessary or 

appropriate to implement a CAA section 111(d) federal plan for 

the affected EGUs located in Indian country. CO2 emission 

performance rates for these facilities were finalized in the 

EGs. Tribes generally may seek “treatment as a state” (TAS) and 

submit a tribal plan to implement CAA programs, including 

programs under CAA section 111(d), and this proposed finding 

does not preclude tribes from doing that. However, tribes are 

not subject to the deadlines applicable to state action under 

the EGs and in the absence of a federal plan, CO2 emissions from 

these EGUs could go unregulated. Therefore, as discussed in 

section VI.D of this preamble, we are proposing a necessary or 

appropriate finding. 

This noticedocument also proposes certain enhancements to 

the process and timing for state submittals and EPA action in 

the CAA section 111(d) framework regulations of 40 CFR part 60,

subpart B (these proposals are not a part of the federal plan or 

model trading rules). These changes, if finalized, would be 

applicable under the Clean Power Plan and other CAA section 
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111(d) rules. These changes clarify the availability of certain 

procedural mechanisms similar to those available under CAA 

section 110 (such as calls for plan revisions and the 

availability of “conditional approvals,” etc.). They also extend 

the deadlines for EPA action, in part to conform with the 

timelines in the EGs. These changes do not alter the timelines 

for state action under the EGs and do not alter the submission 

requirements established in the EGs. Finally, the agency 

proposes to clarify and request comment on an interpretive issue 

raised in the Clean Power Plan proposal regarding whether a 

reconstruction or modification that is subject to a CAA section 

111(b) standard moves an existing source out of a CAA section 

111(d) program. These proposed changes are discussed in section 

VII of this preamble. The agency intends to finalize these 

changes earlier than the finalization of the model trading 

rules.

In proposing a federal plan, the EPA considered a variety 

of potential impacts that its action might have on the 

environment, on businesses, particularly in the energy sector, 

and on the reliability of the electrical grid. The agency gave 

extensive consideration to impacts on vulnerable communities, 

particularly low-income communities, communities of color, and 

indigenous communities. These considerations are generally 
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discussed in &&§ions III, VIII, IX, and X of this preamble.

The agency convened a Small Business Advocacy Review Panel 

under the Regulatory Flexibility Act and has completed an 

Initial Regulatory Flexibility Analysis (IRFA). Various 

recommendations from the Panel are found reflected throughout 

this proposal. In section &&&X of this preamble, the agency 

explains how it has conducted or intends to conduct all other 

statutory or executive order (EO) reviews that apply to this 

proposed action. The EPA also explains in this noticedocument

how it proposes to take into consideration the “remaining useful 

lives” of affected EGUs in the design of the proposed federal 

plan, as discussed below in section &&&III.HG of this preamble.

The agency considered the impacts this action could have on 

the electricity grid and developed options for compliance that 

are cost-effective and ensurethat provide substantial 

flexibility for the affected EGUs that will accommodate the

parties charged with maintaining the reliability of electrical 

power. A key feature of the proposed federal plan and model 

trading rule is that the flexibility inherent in both of the two 

approaches (i.e., rate-based or mass-based trading) enables the 

EPA and the states to create a level of flexibility for affected 

EGUs that allows owners and operators to determine the best way 

to achieve emissions reductions, at the EGU-, state-, multi-
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state-, regional-, or national level. As a result, compliance 

strategies can mirror, or be integrated with, the ongoing 

operations of the current electricity grid as it continues to 

serve its primary critical function of ensuring an uninterrupted 

supply of affordable and reliable electricity. This flexibility 

is especially valuable whenever the need to address specific 

reliability concerns arises. It allows owners and operators of 

reliability-critical EGUs to continue to meet their compliance 

obligations while operating to maintain electric reliability.

The EPA outlined and initiated the Clean Energy Incentive 

Program (CEIP) in the final EGs (see section VIII of the final 

EGs). The program is designed to incentivize investment in 

certain types of renewable energy (RE) projects, as well as

demand-side energy efficiency (EE) projects implemented in lowincome communities, that generate MWh or reduce end-use energy 

demand during 2020 and 20212020 and/or 2021. The EPA proposes to 

apply the CEIP in all states subject to either a rate-based or 

mass-based federal plan.

We also reviewed impacts that this action could have on the 

environment and the need to ensureensu environmental integrity 

of the program as well as avoid unintended environmental 

impacts. We took measures to ensure that the reductions in 

carbon emissions this plan will achieve are real, and not just 
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apparent. As in the EGs, in both the rate- and mass-based

approaches, the EPA has incorporated components to address the 

concern that the dynamics of either a rate- or mass-based 

trading program could incentivize shifting generation from 

existing units in ways that would result in more CO2 emissions 

than would otherwise be expected, or that undermine the purpose 

of the CAA section 111(d) program. 

We considered whether compliance choices under a federal 

plan could lead to an unintended concentration of other air 

pollutants in certain overburdened communities, particularly 

low-income communities and communities of color. As discussed 

below, our analysis shows why we do not expect this to occur at 

any significant level. In general, as in the EGs, we anticipate 

that the federal plan will result in overall reductions of copollutants, in addition to reductions in CO2, with corresponding 

co-benefits to public health. We also reviewed whether this 

action could trigger an obligation to consult with other 

agencies responsible for implementing the Endangered Species 

Act, and propose to conclude that it will not.

In the final emission guidelines, the EPA emphasized the 

importance of state actions to ensure that in developing their 

respective compliance plans the states addressed the concerns 

and priorities of vulnerable communities. In the process of 
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developing a final federal plan, the EPA will also take actions 

to address those concerns as well. In addition to the public 

hearings that the EPA will be holding for all members of the 

American public on this proposed rulemaking, we will also be 

conducting a national webinar and outreach meeting(s) in all ten 

regions on this proposed rulemaking for communities. The goal of 

these outreach activities is to provide communities with the 

information they need to understand how the proposed rulemaking 

will potentially impact their respective communities. At the 

same time, this information will be useful in helping 

communities engage the EPA during our comment period, as well as 

with their states during the state plan development process. We 

will also be providing other outreach and support activities for 

vulnerable communities, which are outlined in the community and 

environmental justice (EJ) considerations section IX.B of this 

preamble.

B. Organization and Approach for this Proposed Rule

In this action, the EPA is proposing a federal plan to 

implement the Clean Power Plan EGs for affected fossil fuelfired EGUs operating in states that do not have approved state 

plans. Specifically, the EPA is co-proposing two different 

approaches to a federal plan to implement the Clean Power Plan 

EGs — a rate-based trading approach and a mass-based trading 
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approach. While establishing emission standards for affected 

EGUs that would be directly enforceable against the owners and 

operators of the source, both approaches would grant EGUs 

substantial flexibility in meeting their compliance obligations. 

For this reason, among others, these proposed approaches also 

serve as two proposed model trading rules that states may adopt 

or tailor in designing their own plans.

The EGs provide that states have until August 31September 

6, 2016 (or later, if extensions are grantedupon making an 

initial submittal, until September 6, 2018) to submit state 

plans, and the EPA does not intend to finalize and implement the

federal plan for any states prior to the agency’s action of 

determining a failure to submit a state plan or disapproving a 

state plan. At the same time, in order to support states’ 

consideration of adoption of one of the model trading rules as 

an approvable state plan, the agency intends to finalize either 

or both model rule options presented in this proposed rule by 

summer 2016, prior to the deadline for state submittals.

The EPA currently intends to finalize a single approach —

i.e., either a rate-based or a mass-based approach — in all 

promulgated federal plans for particular states in order to 

enhance the consistency of the federal trading program, achieve 

economies of scale through a single, broad trading program, 
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ensure efficient administration of the program, and simplify 

compliance options for affected EGUs. We invite comment on which 

approach would be appropriate to finalize for all states.The EPA 

recognizes that the mass-based trading approach would be more 

straightforward to implement compared to the rate-based trading 

approach, both for industry and for the implementing agency. The 

EPA, industry, and many state agencies have extensive knowledge 

of and experience with mass-based trading programs. The EPA has 

more than two decades of experience implementing federallyadministered mass-based emissions budget trading programs 

including the Acid Rain Program (ARP) sulfur dioxide (SO2)

trading program, the Nitrogen Oxides (NOX) Budget Trading 

Program, CAIR, and CSAPR. The tracking system infrastructure 

exists and is proven effective for implementing such programs. 

The EPA requests comment on which approach – mass-based or ratebased trading – is preferred for the federal plan. Some 

stakeholders have suggested there could be utility in the 

availability of both approaches based on the unique 

circumstances of particular states. The EPA recognizes that it 

remains potentially possible to finalize a different approach to 

a federal plan in some circumstances, but believes that in 

general, and consistent with prior federal trading programs such 

as CSAPR, creating a single, broad program has the most 
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advantages. 

The stringency of the proposed federal plan is the same as 

the CO2 emission performance rates established for affected EGUs

in the EGs. As explained in the final EGs, the EPA determined 

the CO2 emission performance rates through the application of the 

best system of emission reduction (BSER).BSER. In the EGs, the 

EPA has taken final action on the BSER for CO2 emissions from 

existing fossil fuel-fired EGUs. Any comments on this proposed

rule relating to the BSER, its stringency, rationale, or legal 

basis, will not be considered as, by definition, they will be 

beyond the scope of this action.3

The state goals, stated as both an aggregated emission 

rate, and as mass-equivalent, are presented in Table 1. [&&& 

insert Table here?]These numbers are the same as those 

established for states in the final EGs. The emission standards 

that the EPA proposes to apply to each affected EGU in the 

federal plan are derived directly from these numbers.

1. The Rate-based Approach

In the first approach, the EPA would implement a rate-based 

 

3 The agency recognizes that the “remaining useful lives” of 

facilities subject to a CAA section 111(d) federal plan is a factor 

that it must consider at the time it implements the federal plan. 

This factor, and how the agency proposes to consider it, is 

discussed in section III.G of this preamble below.
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emissions trading program. In a rate-based program, affected 

EGUs must meet an emission standard, derived from the EGs, 

expressed as a rate of pounds of CO2 per megawatt hour (lbs/MWh). 

If sources emit above their assigned rate, they must acquire a 

sufficient number of emission rate credits (ERC), each 

representing a zero-emitting megawatt hour (MWh), to bring their 

rate of emissions into compliance. ERCs may be generated by 

affected EGUs or by other entities that supply zero- or lowemitting electricity resources to the grid through an approval 

and recognition process that the EPA will administer. ERCs may 

be bought and sold, or banked for use in later years. The ratebased approach is explained in greater detail in section IV of 

thethis preamble.

2. The Mass-based Approach

The second approach to a federal plan that the EPA is 

proposing in this action is a mass-based trading program. In a 

mass-based program, the EPA would create a state emissions 

budget equal to the total tons of CO2 allowed to be emitted by 

the affected EGUs in each state according to, consistent with

the mass-equivalency formula goals established in the EGs. The 

EPA would initially distribute the allowances within each state 

budget – less three proposed allowance set-asides – to the 

affected EGUs based on their historichistorical generation. 
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Allowances may then be transferred, bought, and sold on the open 

market, or banked for future use. The compliance obligation on 

each of the affected EGUs is to surrender the number of 

allowances sufficient to cover the EGU’s respective emissions at 

the end of a given compliance period. The EPA is also proposing 

as a part of the mass-based approach three set-asides of 

allowances: (1) For a Clean Energy Incentive Program; (2) to 

support renewable energyRE projects; and (3) to allocate 

allowances based on an updating measurement of affected-EGU 

generation. The EPA is also proposing that a jurisdiction may 

choose to replace the federal-plan allocation provisions with 

its own allowance-distribution allocation provisions. The massbased approach is explained in greater detail in section V of 

thethis preamble.

3. Other Proposed Actions 

The EPA is proposing in this action a finding that it is 

necessary or appropriate to regulate affected EGUs in certain 

parts of Indian country via a federal plan. This is discussed in 

section [&&& VI.D]. of this preamble.

In this action, the EPA is also proposing a number of 

changes to the framework CAA section 111(d) regulations of 40 

CFR part 60, subpart B. These generally are intended to provide 

enhancements to the process for state plan submissions and the 
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timing of EPA actions related to state plans and the federal 

plan. Specifically, the EPA proposes six changes, to include: 

(1) Partial approval/disapproval mechanisms similar to CAA 

section 110(k)(3); (2) a conditional approval mechanism similar 

to CAA section 110(k)(4); (3) a mechanism for the EPA to make 

calls for plan revisions similar to the "SIP-call" provisions of 

CAA section 110(k)(5); (4) an error correction mechanism similar 

to CAA section 110(k)(6); (5) completeness criteria and a 

process for determining completeness of state plans and 

submittals similar to CAA section 110(k)(1) and (2); and (6) 

updates to the deadlines for EPA action. These proposed changes 

are explained in greater detail in section &&&VII of thethis

preamble. They are not a component of the proposed federal plan, 

or changes in the EGs. If these changes are finalized, they will 

be applicable to other CAA section 111(d) rules. The EPA intends 

to finalize these changes earlier than the finalization of the 

model trading rules.

C. Who Does the Proposed Action Apply to?

Regulated Entities. Existing fossil fuel-fired electric 

generating units (EGUs (or affected EGUs) covered by the final 

Clean Power Plan EGs that are located in a state that does not 

have an EPA-approved state plan are potentially subject to this 

proposed action. Existing fossil fuel-fired Affected EGUs are 
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those that were in operation, or had commenced construction, on 

or before January 8, 20144. The following North American 

Industrial Classification System (NAICS) codes could apply as 

shown in Table 1 belowof this preamble: 

Table 1. Examples of Potentially Regulated Entitiesa

Category

NAICS 

Code

Examples of potentially 

regulated entities

Industry 221112a Fossil fuel electric power 

generating units

State/Local 

Government

221112b Fossil fuel electric power 

generating units owned by 

municipalities

a Includes NAICS categories for source categories that own and operate 

electric power generating units (includes boilers and stationary 

combined cycle combustion turbines). 

b State or local government-owned and operated establishments are 

classified according to the activity in which they are engaged.

This table is not intended to be exhaustive, but rather 

provides a general guide for identifying entities likely to be 

affected by the proposed action. Whether an affected EGU is

affected by this action is described in the applicability 

 

4 An affected EGU is any fossil fuel-fired EGU that was in operation 

or had commenced construction as of January 8, 2014, and is 

therefore an “existing source” for purposes of CAA section 111, 

but in all other respects would meet the applicability criteria 

for coverage under the GHG standards for new fossil fuel-fired 

EGUs. 
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criteria in 40 CFR 60.5845 and 60.5850 of subpart UUUU. 

Questions regarding the applicability of this action to a 

particular entity should be directed to the person listed in the 

preceding FOR FURTHER INFORMATION CONTACT section.

1. What is an Affected Electric Utility Generating Unit?

For the federal plan, the definition of an affected 

electric generating unit (EGU) is identical to the definition in 

the final Clean Power Plan EGs. Additionally, the applicability 

of the federal plan is consistent with the EGs, where an 

affected EGU subject to the federal plan is any steam generating 

unit, (SGU), integrated gasification combined cycle unit (IGCC), 

or stationary combustion turbine (SCT) that was in operation or 

had commenced construction as of January 8, 2014,5 and that meets 

certain criteria, which differ depending on the type of unit. 

The criteria to be an affected EGU are as follows: A unit, if it 

is a steam generating unitSGU or IGCC, must serve a generator 

capable of selling greater than 25 MW (Megawatts) to a utility 

power distribution system, have a base load rating greater than 

260 GJ/hrh (250 MMBtu/hrh) heat input of fossil fuel (either 

alone or in combination with any other fuel), and historically 

 

5 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).
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have supplied more than 1/3 of its potential electric output and 

219,000 MWh as net-electric sales on any 3 calendar year basis. 

If a unit is a stationary combustion turbineSCC, the unit must 

meet the definition of a combined cycle or combined heat and 

power (CHP) combustion turbine, serve a generator capable of 

selling greater than 25 MW to a utility power distribution 

system, have a base load rating of greater than 260 GJ/h (250 

MMBtu/hrh), and historically have combusted more than 90 percent

natural gas on a heat input basis on an annual basis. 

2. How to Determine if a Unit is Covered by an Approved and 

Effective State Plan

Section 111(d) of the CAA, as amended, 42 U.S.C. 7411(d), 

authorizes the EPA to develop and implement a federal plan for 

affected EGUs upon the EPA’s action finding a failure to submit 

or disapproving a state plan.6 The affected EGUs covered in EPAapproved state plans are not subject to the federal plan. If the 

 

6 In this Preamble, the term “state” generally encompasses the 50 

states and the District of Columbia, U.S. territories, and any 

Indian Tribe that has been approved by the EPA pursuant to 40 CFR 

49.9 as eligible to develop and implement a CAA section 111(d) 

plan. However, the federal plan is not proposed for affected EGUs 

in certain states or territories where the EGs did not finalize 

emission performance rates. 
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federal plan has been put in place in a state, but is later 

replaced by an EPA-approved state plan, the affected EGUs would 

become subject to the state plan as of the effective date 

specified in a Federal Register notice regarding the EPA’s 

approval of the state plan. The EPA is not expecting state plans 

to be submitted by the states that submit negative declarations. 

However, in the event that there are later determined to be

affected EGUs located in these states, the final federal plan 

would be applied to such EGUs through a future action. Part 62 

of Title 40 of the CFR identifies the status of approval and 

promulgation of CAA section 111(d) state plans for designated 

facilities in each state. Recognizing the urgent need for 

actions to reduce GHG emissions, and in accordance with the 

Presidential Memorandum7, as well as the benefit of providing 

states with model trading rule options to consider as they 

prepare their state plans, the EPA is proposing this rulemaking 

concurrently with the Administrator’s signing and promulgation 

of the final Clean Power Plan EGs. 40 CFR part 62 is updated 

only once per year. Thus, if 40 CFR part 62 does not indicate 

 

7 Presidential Memorandum—Power Sector Carbon Pollution Standards, 

June 25, 2013. http://www.whitehouse.gov/the-pressoffice/2013/06/25/presidential-memorandum-power-sector-carbonpollution-standards.
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that your state has an approved and effective plan after the 

compliance date has passed requiring state plan submittal, you 

should contact your state environmental agency’s Air Director or 

your EPA Regional Office (see Table &&&XXX2 in section II.DB of 

this preamble) to determine if approval occurred since 

publication of the most recent version of 40 CFR part 62.

D. What Should I Consider as I Prepare my Comments?

Do not submit information that you consider to be CBI 

electronically through http://www.regulations.gov or email. Send 

or deliver information identified as CBI to only the following 

address: 

OAQPS Document Control Officer (Room C404-02), U.S. EPA, 

Research Triangle Park, NC 27711, Attention Docket ID No. EPAHQ-OAR-2015-0199. Clearly mark the part or all of the 

information that you claim to be CBI. For CBI on a disk or CDROM that you mail to the EPA, mark the outside of the disk or 

CD-ROM as CBI and then identify electronically within the disk 

or CD-ROM the specific information that is claimed as CBI. In 

addition to one complete version of the comment that includes 

information claimed as CBI, a copy of the comment that does not 

contain the information claimed as CBI must be submitted for 

inclusion in the public docket. Information marked as CBI will 

not be disclosed except in accordance with procedures set forth 
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in 40 CFR part 2.

If you have any questions about CBI or the procedures for 

claiming CBI, please consult the person identified in the FOR 

FURTHER INFORMATION CONTACT section.

2. Docket. The docket number for the proposed action (40 CFR 

part 62, subpart MMM) is Docket ID No. EPA-HQ-OAR-2015-0199.

3. World Wide Web (WWW). In addition to being available in the 

docket, an electronic copy of the proposed action is available 

on the WWWInternet through the EPA’s Technology Transfer Network 

(TTN) Web site. , a forum for information and technology 

exchange in various areas of air pollution control. Following 

signature by the EPA Administrator, the EPA will post a copy of 

the proposed action at wwwhttp://www2.epa.gov/airtoxics/XX. The 

TTN provides information and technology exchange in various 

areas of air pollution control. Additional information is also 

available atcleanpowerplan/regulatory-actions#regulations. 

Following publication in the Federal Register (FR), the EPA will 

post the FR version of the proposed rule and key technical 

documents on the same Web site. 
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II. Background Information

A. What is the Regulatory Development Background for this 

Proposed Rule?

On &&&August 3, 2015, the EPA finalized the Clean Power 

Plan EGs for existing fossil-fuel fired EGUs (40 CFR part 60,

subpart UUUU) under authority of section 111 of the CAA (79 FR

34950). The Guidelines apply to existing fossil-fuel fired EGUs, 

i.e., those that were in operation or had commenced construction 

before January 8, 2014. States with existing EGUs subject to the 

guidelines are required to submit to the EPA by August 

31September 6, 2016, a state plan that implements the EGs. 

States may also make initial plan submittals in lieu of a 

complete state plan, in which case extensions canwill be granted 

until September 6, 2018 (40 CFR &&&).Supbart UUUU).8 As discussed 

in section VI.D of this preamble, Indian Tribes may, but are not 

required to, submit tribal plans. Once the EPA finds that a 

state has failed to submit a plan, or disapproves a state plan,9

 

8 See Section VII of this preamble for additional information on 

proposed changes to 40 CFR 60.27 to provide enhancements and 

flexibilities to the agency’s process for review and action on 

state plans and promulgation of federal plans.

9 If a state has submitted a complete plan, then the EPA will go 

through a public notice and comment process to fully or partially 

approve or disapprove the state plan. 
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section 111 of the CAA and 40 CFR 60.27 require the EPA to 

develop, implement, and enforce a federal plan for existing EGUs

located in that state. In addition, CAA section 301(d)(2) 

authorizes the Administrator to treat an Indian Tribe in the 

same manner as a state for this EGU requirement. See 40 CFR 

49.3; see also ‘‘“Indian Tribes: Air Quality Planning and 

Management,’’,” hereafter ‘‘“Tribal Authority Rule,’’,” (63 FR 

7254, February 12, 1998). As discussed in section VI.D of this 

preamble, the agency in this action is proposing a necessary or 

appropriate finding for the affected EGUs in several areas of 

Indian country and is proposing the federal plan for these 

affected EGUs.

The agency believes it is appropriate to propose the 

federal plan at this time for any states that may ultimately be 

found to have failed to submit a plan, or had their plan 

disapproved by the EPA. For some states in this situation, the 

federal plan may be no more than an interim measure to ensure 

that congressionally mandated emission standards under authority 

of section 111 of the CAA are implemented until they can get an 

approved plan in place. Other states may choose to rely on the 

federal plan and would not need to develop their own plan. This 

proposal also serves as two proposed model trading rules which 

states can adopt or tailor for adoption as their state plan. The 
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role of the model rules is discussed in the following section.

In this proposal, the EPA is soliciting public comment only 

on the proposed approaches for a federal plan and model trading 

rule for the implementation of the Clean Power Plan EGs. 

Comments on the underlying Clean Power Plan rule will be 

considered out ofoutside the scope for this actionproposed rule.

B. What is the Purpose of this Proposed Rule?

The purpose of this action is two-fold: (1) To co-propose 

two approaches to a federal plan to implement the Clean Power 

Plan EGs for affected EGUs operating in any state lacking an 

approved state plan by the relevant deadlines; and (2) to 

propose these same approaches as model trading rules for states 

to consider in developing their own plans.

1. Federal plan

Section 111 of the CAA and 40 CFR 60.27 require the EPA to 

develop, implement and enforce a federal plan to cover existing 

EGUs located in states that do not have an approved plan. 

Section 111(d) of the CAA relies upon states as the preferred 

implementers of EGEGs for existing EGUs. States with affected 

EGUs are to submit state plans or make initial submittals to the 

EPA by August 31September 6, 2016 that are at least as 
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protective aspursuant to the EGs.10 States without any existing 

EGUs are directed to submit to the Administrator a letter of 

negative declaration certifying that there are no affected EGUs 

in the state. No plan is required for states that do not have 

any affected EGUs. Affected EGUs located in states that 

mistakenly submit a letter of negative declaration will become

subject to the federal plan until a state plan covering those 

EGUs becomes approved. The EPA intends to finalize the federal 

plan only for those states that the EPA finds failed to submit 

plans or whose plans the EPA disapproves. For more information 

on the timing and mechanics of EPA action on state plans and 

finalization of this federal plan, see section II.D.1 of this 

preamble below.

2. Model Trading Rule

The EPA is also proposing the federal plan approaches as 

two forms of a model trading rule (mass-based and rate-based), 

which states can adopt or tailor for implementation as a state 

plan under the EGs. The EPA intends to finalize the model 

trading rules earlier than it promulgates a federal plan for a 

state. When the EPA finalizes one or both of its proposed 

approaches as a final model trading rule, and a state adopts a

 

10 States may request extensions of up to two years as part of a 

complete initial CAA section 111(d) submission.
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final model trading rule in its entirety as its state plan, it 

would be presumptively approvable.

The EPA has designed these rules so that they meet the 

requirements of the final EGs. If one of the model rules is 

adopted by a state without any change, it would be presumptively 

approvable. We use the term “presumptively” in recognition that 

a state plan submission must be accompanied by other materials 

in addition to the regulatory provisions. These requirements are 

set forth in the final CPP EGsClean Power Plan and framework 

regulations of 40 CFR part 60, subpart B. For instance, they 

include a formal letter of submittal from the Governor or his or 

her designee, evidence that the rule has been adopted into state 

law and that the state has necessary legal authority to 

implement and enforce the rule, and evidence that procedural 

requirements, including public participation under 40 CFR 60.23, 

have been met. 

In further support of state use of the model rules, we are 

drafting the model trading rule so that it can be adopted or 

incorporated by reference with a minimum of changes that would 

be necessary to make the rule appropriate for use by states. 

This way, a state may incorporate by reference the model rule as 

the state plan, or as the backstop to a state measures plan with 

few if any adjustments. States may make changes to the model 
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trading rule, so long as they still meet the requirements of the 

EGs. If the state chooses to tailor or modify the model trading 

rule such as by expanding the scope of eligibility of projects 

that may generate ERCs in a rate-based trading program, the EPA 

may still approve the plan, but the EPA would conduct 

appropriate review of such provisions for consistency with the 

EGs and the state would have to demonstrate to the EPA’s 

satisfaction that its alternative provisions are as stringent as 

the presumptively approvable approach described. We note here, 

and as a “note” in the regulatory text of the model trading 

rule, that the scope of eligibility of proposed “ERC resources” 

for the federal plan is different than the scope of eligibility 

provided for in the model rule. Thus, all of the language and 

provisions in the regulatory text relevant to these other ERC 

resources is relevant only to the proposed model trading rule 

and not to the federal plan as such. (i.e., those ERC resources 

discussed in section IV.C.3 of this preamble are applicable to 

the model rule and only metered RE and applicable nuclear are 

applicable to the federal plan).

The EPA’s approval of a state plan, including a plan that 

adopts the model trading rule, will be the result of an 

independent notice-and-comment rulemaking process. Without 

prejudging the outcome of that process, the EPA recognizes that 
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it may be able to approve or “conditionally approve” state plans 

that are substantially similar, but not identical to, the final

model trading rules. Ultimately, state plans must meet the 

requirements of the EGs for approvability. Thus, a conditional

approval would be based on a condition that the state take such 

actions as may be necessary by a date certain to meet the 

requirements of the EGs. (The EPA is proposing to explicitly 

provide for conditional approvals in the CAA section 111(d) 

framework regulations. See section VII.B of this preamble.)

In accordance with the EGs, the process for review and 

approval (or disapproval) of state plans, whether based on the 

model trading rules or otherwise, would occur once the states 

have made their submissions by August 31September 6, 2016. As 

provided in the EGs, states have the option of not submitting a 

full state plan, but rather making an initial submittal, in 

order to obtain an extension of two2 years before submitting a 

full state plan for EPA approval. The EPA believes It could be 

beneficial for coordination purposes if a state that is 

interested in adopting one of the model trading rules andbut

intends to make an initial submittal rather than submit a full 

plan next Augustyear were to indicate this, and which one, in 

their submittalmodel trading rule they intend to adopt. This is 

not an additional requirement beyond what the EGs require for 
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initial submittals, however.

The EPA strongly encourages states to consider adopting one 

of the model trading rules, which are designed to be referenced 

by states in their rulemakings. Use of the model trading rules

by states would help to ensure consistency between and among the 

state programs, which is useful for the potential operation of a 

broad trading program that spans multi-state regions or operates

on a national scale. As discussed at length in the EGs, EGUs 

operate less as individual, isolated entities and more as 

multiple components of a large interconnected system designed to 

integrate a range of functions that ensure an uninterrupted 

supply of affordable and reliable electricity andwhile also, for 

the past several decades, maintaining compliance with air 

pollution control programs. Since, as a practical matter under 

both the EGs and any federal plan, emissions reductions must 

occur at the affected EGUs, a broad-scale emissions trading 

program would be particularly effective in allowing EGUs to 

operate in a way that achieves pollution control, without 

disturbing the overall system of which they are a part and the 

critical functions itthat this system performs. In addition, 

consistency of requirements benefits the affected EGUs, as well 

as the states and the EPA in their roles as administrators and

implementers of a trading program. States of course remain free 
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to develop a plan of their own choosing to submit to the EPA for 

approval following the criteria set out in the final Clean Power 

Plan EGs. 

The EPA believes there are compelling policy reasons that 

support the provision of a proposed model trading rule at this 

time. The EPA has heard from multiple stakeholders and in public 

comments submitted on the proposed EGs that there is a strong 

interest in seeing a model state plan or trading rule prior to 

the deadline for state submittals under the EGs. According to 

these stakeholders, model rules can provide predictability for 

planning purposes, both among states and affected EGUs. In 

addition, some states have indicated that they may prefer to 

rely on a federal plan, either temporarily or permanently,

rather than develop a plan of their own. This proposal of a 

model trading rule addresses these policy interests.

The approach of proposing model trading rules that are 

identical in all key respects to proposed federal plans that may 

be promulgated later, is consistent with prior CAA section 

111(d) and CAA section 110 rulemakings. For example, the NOx

state implementation plan (SIP) Call model rule at 40 CFR part 

96 (63 FR 57356; Oct. 27, 1998) was identical in all meaningful 

respects with the Federal NOx Budget Trading Program at 40 CFR 

part 97 (65 FR 2674; Jan. 18, 2000). And the Clean Air 
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Interstate Rule (CAIR) model rule in 40 CFR part 96 (70 FR 

25339; May 12, 2005) was identical in all meaningful respects 

with the federal CAIR in 40 CFR part 97 (71 FR 25396; April 28, 

2006).11 While these identical programs for model rules and 

Federal Implementation Plans (FIPs) were finalized in separate 

parts of the Code of Federal RegulationsCFR, the EPA does not 

see any reason that it could not just as easily propose the 

federal plan as the model trading rule in the same section of 

the CFR.12 If a federal plan were to be finalized for a given 

state at a later time, this would be reflected in 40 CFR part 62

by cross-reference, along with any modifications or adjustments 

that may be appropriate at the time of actual promulgation of a 

federal plan.

Table 32. Regional Office Contacts

Region Regional contact Phone

States and 

protectorates

Region I Shutsu Wong

wong.shutsu@epa.gov

617-918-1078 Connecticut, 

Massachusetts, 

Maine, New 

Hampshire, Rhode 

 

11 We also note that historically under the CAA section 111(d)/129 

rules, the content of EGs and their corresponding federal plans 

have had significant overlap.

12 We propose to include a note in the regulatory text explaining 

where aspects of the proposed subpart relevant to states as part 

of the model trading rule are not applicable 
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Region Regional contact Phone

States and 

protectorates

Island, Vermont

Region II Gavin Lau

lau.gavin@epa.gov

212-637-3708 New York, New 

Jersey, Puerto 

Rico, Virgin 

Islands

Region III Mike Gordon

gordon.mike@epa.gov

215-814-2039 Virginia, 

Delaware, 

District of 

Columbia, 

Maryland, 

Pennsylvania, 

West Virginia

Region IV Ken Mitchell

mitchell.ken@epa.gov

404-562-9065 Florida, Georgia,

North Carolina, 

Alabama, 

Kentucky, 

Mississippi, 

South Carolina, 

Tennessee

Region V

 

Alexis Cain

cain.alexis@epa.gov

312-886-7018 Minnesota, 

Wisconsin, 

Illinois, 

Indiana, 

Michigan, Ohio

Region VI Rob Lawrence

lawrence.rob@epa.gov

214-665-6580 Arkansas, 

Louisiana, New 

Mexico, Oklahoma, 

Texas

Region VII Ward Burns

burns.ward@epa.gov

913-551-7960 Iowa, Kansas, 

Missouri, 

Nebraska
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Region Regional contact Phone

States and 

protectorates

Region VIII Laura Farris

farris.laura@epa.gov

303-312-6388 Colorado, 

Montana, North 

Dakota, South 

Dakota, Utah, 

Wyoming

Region IX Ray Saracino

saracino.ray@epa.gov

415-972-3361 Arizona, 

California, 

Hawaii, Nevada, 

American Samoa, 

Guam, Northern 

Mariana Islands

Region X Madonna Narvaez

narvaez.madonna@epa.gov

206-553-2117 Alaska, Idaho, 

Oregon, 

Washington

C. Legal Authority 

Section 111(d)(2) of the CAA, 42 U.S.C. 7411(d)(2) provides 

the EPA the same authority to prescribe a plan for a state in 

cases where the state fails to submit a satisfactory plan as the 

agency would have under CAA section 110(c) in the case of 

failure to submit an implementation plan. In addition, the EPA 

has authority under CAA section 111(d)(1) to prescribe 

regulations that establish procedures similar to CAA section 110 

with respect to the submission of state plans, and the EPA also 

has general rulemaking authority as necessary to implement the 

CAA under CAA section 301. A federal plan under CAA section 
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111(d) applies, implements and enforces standards of performance 

for affected EGUs. &&&Under the Clean Power Plan EGEGs, state

plans will be due on [August 31September 6, 2016]., but states 

are also allowed to seek a two year extension for a final plan

submittal, upon submitting a satisfactory initial plan submittal

by the same deadline. See 40 CFR 60.5755, 60.5760(b). If a state 

does not submit a final state plan or initial plan submittal,13

or if either a final state plan or an initial plan submittal,

does not meet the requirements of the EG, the agency will take 

the appropriate steps to finalize and implement a federal plan 

tofor that state’s EGUs. 

Further, states will remain free, and indeed are strongly 

encouraged, to submit an approvable state plan even after 

promulgation of the federal plan for their jurisdictions. Upon 

 

13 Indeed, states may simply choose to accept a federal plan in 

lieu of undertaking to develop a state plan at all. While the 

statute uses the phrase “fails to submit a satisfactory plan,” the 

EPA does not believe this should carry any pejorative connotation. 

While Congress identified states and local governments as having 

“primary responsibility” for air pollution prevention and control, 

CAA section 101(a)(3), states are in no way penalized for not 

submitting a plan under CAA section 111(d). Rather, the EPA steps 

into the shoes of the state to carry out the CAA section 111(d) 

program in its stead. To the extent states may be interested in 

accepting a federal plan, the EPA would be interested in hearing 

that through the comment process on this proposal.
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approval of the state plan by the EPA, the federal plan will no 

longer apply to the affected EGUs covered by the state plan. See

&&&40 CFR 60.5720.

D. Timing of EPA Actions on the Model Trading Rules, Federal 

Plan, and other Proposed Actions

This action co-proposes two approaches to the federal plan, 

both of which also constitute proposed model trading rules that 

states could adopt as state plans for EPA approval. The EPA 

currently intends to finalize one or both of the model trading 

rules by next summer so that they may be available to states as 

soon as possible to help inform their state plan development 

efforts prior to the initial submittal deadline of August 31, 

2016September 6, 2016, and two years before the states’ final 

plan deadline of September 6, 2018.14 If the EPA finalizes the 

model trading rules in that timeframe, the only direct 

consequence will be to provide the states certainty as to one or 

two particular approaches to the design of their state plan that 

the EPA will approve if adopted in full. The finalization of a 

 

14 We anticipate that the model rules’ text could be finalized 

either in a new subpart or subparts of 40 CFR part 62 of title 40 

of the CFR as proposed, or in a final document that is not published 

in the CFR.
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model trading rule will not constitute a final action with 

respect to a federal plan for the affected EGUs in any state. 

Rather, the proposed federal plan will remain just that, a 

proposal. The EPA will promulgate a final federal plan for any 

state only after it has made a finding on a state’s failure to 

submit a plan, or fully or partially disapproved a submitted 

state plan. The EPA will go through a public notice and comment 

process before disapproving a submitted and complete state plan, 

in whole or part. The EPA invites comments on this staged 

approach to finalizing one or more model trading rules on the 

one hand (which we currently intend to do in summer 2016), and 

finalizing federal plans on the other (which we currently intend 

to do state-by-state upon our taking predicate action on states’ 

plans).

In this action, the EPA is also proposing enhancements to 

the process for agency action on state submittals and 

promulgation of a federal plan under CAA section 111(d). For 

more detailed discussion of these changes, see &&§ion VII of 

this preamble. This aspect of this proposal is separate from the 

federal plan and the model trading rules. The EPA intends to 

finalize these changes on a timeline earlier than both a model 

trading rule and the federal plan. 

Under the framework regulations and the final EGs, at 40 
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CFR part 60.27 and &&&60.5715 and &&&5760, respectively, the 

initial timelines for EPA action on state submittals and, 

potentially, the promulgation of a federal plan will be as 

follows: the EPA will have twelve12 months from the date of a 

state's submission to approve or disapprove that state’s plan. 

The EPA will have twelve12 months from the date of its action on 

a state submission to promulgate the federal plan for the EGUs 

in that state. The EPA will have six6 months from the date of a 

state’s submission to notify a state that its submittal does not 

meet completeness criteria and constitutes a failure to submit a 

plan. In the case of initial submittals under 60.5765, the EPA 

will have 60 days from August 31September 6, 2016 to notify a 

state that its initial submittal does not meet the requirements 

of 60.5760(a). As with state plans, the EPA will have twelve12

months to promulgate a federal plan from the date of its finding

that a state failed to submit a complete and approvable initial

submittal. (Formally, such a finding would be that the state 

failed to submit a state plan.)

The timeframes stated in the previous paragraph reflect the 

maximum time allowed for EPA action. We note that under CAA 

section 111(d)(2) and CAA section 110(c), the EPA may promulgate 

a final federal plan for a state immediately upon making a 

finding of failure to submit a complete state plan or initial
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submittal, or upon making a finding of final disapproval of a 

state plan. Congress gave the EPA authority in CAA section 

111(d)(2), as it did in CAA section 110(c), to promulgate a 

federal plan at any time after it disapproves or finds a failure 

to submit a state plan. The Supreme Court has recognized that 

under this authority, the EPA may promulgate a FIP “at any time” 

within the two2-year limit of CAA section 110(c) “that begins 

the moment EPA determines a SIP to be inadequate.” EME Homer 

City v. EPA, 134 S. Ct. 1584, 1601 (2014). “EPA is not obliged 

to wait two years or postpone its action even a single day . . . 

.” Id.,. It is essential to implement plans for the control of 

emissions of carbon dioxideCO2 expeditiously and avoid 

unnecessary delay. Among other reasons, this will provide 

affected EGUs regulatory certainty and will assist the regulated 

entities as well as those authorities with responsibility for 

ensuring grid reliability to have as much time as possible to 

plan for the 2022 compliance start date set in the EGs. Thus, it 

is reasonable to propose this federal plan now so that federal 

plans will be ready to be promulgated quickly in cases where

states have failed to submit a plan or their plans are found

unsatisfactory. 

It is the agency’s intention to promulgate federal plans 

promptly for states who do not submit plans or initial
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submittals by August 31 of next year.September 6, 2016. However, 

the effect of putting the federal plan in place at that time 

would ultimately be limited in impact upon states. Because the 

EPA would implement the federal plan, its promulgation does not 

obligate state officials to take any actions themselves. 

Further, states remain free - and the EPA in fact encourages 

states - to submit state plans that can replace the federal 

plan. States can do so in advance of the beginning of the 

performance period in 2022, or may transfer to a state plan 

after that date. However, in doing so, the agency and states 

should be mindful of the goals of regulatory certainty discussed 

in the prior paragraph.

Because we are proposing a federal plan that would apply 

emission standards to affected EGUs in all states that the 

agency determines not to have an approvable plan, the EPA

invites comment from all persons with concerns about or comments 

on the proposed federal plan as it may apply in any state, 

whether or not that state has submitted, or intends to submit,

its own plan on which the EPA has yet to take action.

In this noticedocument, the EPA is proposing regulatory 

text setting out the substantive provisions for both of the 

proposed federal plans/model trading rules. The EPA is not 

providing specific regulatory text that would, if finalized,
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actually promulgate a federal plan for each state for which this 

proposed federal plan might be applied.15 We currently envision 

that this language would be in the form of a new section to the 

state-specific subparts of part 62 and would be ministerial in 

nature. It would likely provide that the affected EGUs in each 

such state are subject to a federal plan and would then crossreference or incorporate by reference the substantive provisions 

of one of the two subparts proposed todayin this action (if 

finalized), along with any applicable modifications or 

adjustments as may be necessary, either based on new information 

or in response to comments regarding the application of the 

federal plan to that particular state. This text may appear

similar to the FIP language found in the final CSAPR rule (76 FR 

48208, 48361-78; August 8, 2011).

E. Use of the Model Trading Rule as a Backstop

As discussed in the final EGs, &&&citation, the EPA 

believes that either a mass-based or rate-based model trading 

rule could function well as the federally enforceable “backstop” 

that the EGs require to be included in “state measures” type 

 

15 The minimum contents of a notice of proposed rulemaking under 

the CAA are set forth at CAA section 307(d)(3) and 5 U.S.C. 553(b). 
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state plans.16 (The proposed federal plan does not itself require 

a “backstop” because it relies on an “emission standards” 

approach, rather than a “state measures” approach, as delineated 

in the final EGs.) The conditions and requirements for the 

federally enforceable backstop in a state measures approach are 

discussed in detail in the final EGs. See &&§ion VIII.C.43.b 

and &&&VIII.C.46.c.2 of the final EGs. To summarize those 

provisions, without reopening them for comment, the federally 

enforceable backstop must fully achieve the CO2 emission 

performance rates or the state’s interim and final CO2 emission 

goal if the state plan fails to achieve the intended level of CO2

emission performance. The state plan submittal must identify the 

federally enforceable emission standards for affected EGUs that 

would be used in the backstop, demonstrate that those emission 

standards meet the requirements that apply in the context of an 

emission standards approach, identify a schedule and trigger for 

implementation of the backstop that is consistent with the 

requirements in the EGs, and identify all necessary state 

 

16 We are aware of at least one case in which a court has upheld 

the use of a trading program as a backstop to ensure CAA 

requirements are met. See WildEarth Guardians v. U.S. EPA, No. 12-

9596 (10th Cir. filed Oct. 21, 2014) (upholding use of backstop 

cap-and-trade program under 40 CFR 41.309 of the Regional Haze 

Rule). 
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administrative and technical procedures for implementing the 

backstop (e.g., how and when the state would notify affected 

EGUs that the backstop has been triggered). In addition, the 

backstop emission standards must make up for any shortfall in CO2

emission performance during a prior plan performance period that 

led to triggering of the backstop.

The EGs explicitly recognized that the backstop emission 

standards could be based on one of the model trading rules that 

the EPA is proposing in this action. As discussed in section 

II.B of this preamble above, we are drafting the model trading 

rule so that it can be adopted or incorporated by reference with 

a minimum of changes necessary to make the rule appropriate for 

use by states, and this includes its use as a backstop. 

Instances of this approach are throughout the proposed rule text 

and reflect our desire to ease the use of the model rule for 

states, as a full state plan, or as a backstop to a “state 

measures” plan.

One way in which a backstop may need to differ from the 

model trading rules proposed in this action is the requirement 

to make up for a shortfall in emissions performance in a state’s 

prior plan performance period. The model trading rules do not 

provide provisions that would automatically adjust the emission 

standards to account for any prior emission performance 
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shortfall (which is an option states have if designing their own 

backstop). Thus, a state relying on the model trading rule as 

its backstop would likely need to submit an appropriate revision 

to the backstop emission standards adjusting for the shortfall 

through the state plan revision process. This would likely be 

done in conjunction with the process for putting the backstop 

into effect.

If a state chooses to use the model rule as its federally 

enforceable backstop in a state measures plan, this does not 

mean that the backstop is itself the federal plan. Rather, the 

model rule becomes adopted as a part of the state plan. Both 

approaches to the model trading rule are “emission standard” 

approaches under the EGs, in which where an emissions standard 

in the form of an allowable rate of emissions, or an allowance 

system, emission standard is imposed and federally enforceable 

on the affected EGUs: in the rate-based approach the emissions 

standard is an allowable rate of emissions; in the mass-based 

approach the emission standard is the requirement to hold 

allowances equal to reported emissions. The EPA may also handle 

the administration of the trading program for states utilizing 

the model trading rule. However, even though the backstop may 

take the form of an EPA-administered, federally-enforceable 

trading rule, this does not mean that a federal plan has been 
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put into effect. The state retains all of its rights and 

responsibilities with respect to the implementation and 

enforcement of the backstop as a component of its state plan.

1. Applicability and Enforceability

If promulgated for the affected EGUs in a particular state, 

this federal plan will require affected EGUs to meet specific 

emission standards for CO2 and related requirements. These

enforceable compliance obligations will apply to the owners and 

operators of those affected EGUs. See 40 CFR 62.13. No

obligation falls on states or state officials (except to the 

extent they may be owners and operators of affected EGUs).17 In 

the event of noncompliance, the provisions in the federal plan

are federally enforceable against an affected EGU, in the same 

manner as the provisions of an approved state plan under CAA 

section 111(d), and similar to a FIP or an approved SIP under 

 

17 See Reno v. Condon, 528 U.S. 141, 151 (2000). State officials 

responsible for developing state plans, however, should be aware 

of the procedural enhancements being proposed to the framework 

regulations of 40 CFR part 60, subpart B, in this rulemaking 

document. These changes are discussed in section VII of this 

preamble below. These changes are not a component of the proposed 

federal plan or the EGs. Although these changes do not alter the 

deadlines or submission obligations provided in the Clean Power 

Plan Emission Guidelines, state officials and other interested 

parties are encouraged to review and comment on these changes.
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CAA section 110. See CAA section 111(d)(2)(B), 42 U.S.C. 

7411(d)(2)(B) (power to enforce state and federal plans), 

section 113(a)–(h), 42 U.S.C. 7413(a)-(h), and section 304, 42 

U.S.C. 7604. This means that the Administrator has the ability 

to enforce against violations and secure appropriate corrective 

actions pursuant to CAA sections 113(a)–(h), and states and 

other third parties maintain the ability to enforce against 

violations and secure appropriate corrective actions pursuant to 

CAA section 304.

III. Federal Plan Structure to Achieve Reductions

A. Overview

1. Interactions with State Plans and Scope of Trading

The EPA intends to set up and administer a program to track 

trading programs – both rate-based and mass-based – that will be 

available for all states that choose it. The EPA proposes that 

affected EGUs in any state covered by a federal plan could trade 

compliance instruments with affected EGUs in any other state 

covered by a federal plan that uses the same approach.or a state 

plan meeting the conditions for linkage to the federal plan. In 

the proposed mass-based federal-plan trading program, this would 

mean that affected EGUs in a state covered by the federal plan 

or a state meeting the conditions for linkage to the federal 
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plan could use, as a compliance instrument, an allowance 

distributed in any other state covered by the federal plan. or a 

state meeting the conditions for linkage to the federal plan.

Similarly, in the proposed rate-based federal-plan trading 

program approach, this would mean that affected EGUs in a state

covered by the federal plan or a state meeting the conditions 

for linkage to the federal plan could use, as a compliance 

instrument, an ERC issued in any other state covered by the 

federal plan. or a state meeting the conditions for linkage to 

the federal plan. We propose that an affected EGU in a state 

covered by the mass-based trading federal plan must use 

allowances for compliance (not ERCs). Similarly, an affected EGU 

in a state covered by the rate-based trading federal plan must 

use ERCS for compliance (not allowances).

The agency promulgated provisions for “ready-for-interstatetrading” plans in the EGs. The EPA is proposing the federal 

plans as ready-for-interstate-trading plans. States plans that 

adopt the model rule are also considered ready-for-interstatetrading. The EPA proposes to allow interstate trading between 

affected EGUs in states covered by the proposed federal plans

and affected EGUs in states covered by state plans (referred to 

below as “linking” states, or “linkages”) under the following

conditions, which are discussed further below the list:
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• The state plan must be approved.

• The state plan must implement the same type of trading 

program as the federal plan trading program in order to be 

linked for interstate trading, i.e., mass-based trading 

programs can link to mass-based trading programs only, and 

rate-based trading programs can link to rate-based trading 

programs only.

• The state plan must use the identical compliance instrument 

as the federal plan (this requirement is detailed below).

• The state plan must be approved as a ready-for-interstatetrading plan.

• The state plan must use an EPA-administered tracking system

(we are also requesting comment on expanding this to 

include a state plan that uses an EPA-designated tracking 

system that is interoperable with an EPA-administered 

system, as detailed below).

The EPA proposes that interstate ERC trading could occur 

both 1) from affected EGUs in states covered by the rate-based 

trading federal plan to affected EGUs in states with approved 

rate-based trading state plans meeting the proposed conditions

for linkages, (including the conditions for being “ready-forinterstate-trading” that were finalized in the EG), and 2) from 
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affected EGUs in such state-plan-covered states to affected EGUs

in federal-plan-covered states. The EPA also requests comment on 

expanding the scope of interstate trading to include linking 

states covered by the rate-based trading federal plan with any 

state that has an approved rate-based trading state plan meeting 

the proposed conditions for linkages and that uses an EPAdesignated ERC tracking system that is interoperable with an 

EPA-administered ERC tracking system. The EPA also takes comment 

on allowing a state that has an approved rate-based trading 

state plan meeting the proposed conditions for linkages and that 

uses an EPA-designated ERC tracking system to register with the 

EPA, and after registration, to link with states covered by the 

rate-based trading federal plan. There are multiple benefits to 

a registration requirement, which include ensuring that the 

tracking systems are functionally interoperable.

For the mass-based federal plan, the EPA proposes that 

interstate allowance trading could occur in both directions, 

i.e., from affected EGUs in states covered by the mass-based 

trading federal plan to affected EGUs in states with approved 

mass-based trading state plans meeting the proposed conditions

for linkages, and from affected EGUs in such state-plan-covered 

states to sources in federal-plan-covered states.

The EPA proposes that a condition of linkage between a 
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state plan and the federal plan is the use of an identical 

compliance instrument. In the mass-based federal plan the EPA 

proposes to issue allowances in short tons, thus; as a condition 

of result, the EPA is proposing in this rule that linkage tofor

the mass-based federal plan is that alimited to state plan 

mustplans that issue its allowances in short tons. The agency 

also requests comment on whether to extend linkage to state 

plans that issue allowances in metric tons and on what 

provisions would be necessary to implement such linkages. The 

EPA believes that considerations for linkages to state plans 

that use metric tons may include tracking system design, and 

stipulation of which parties convert allowance valuesstate plan 

allowances denominated in metric tons to allowances denominated 

in short tons and at what stage of compliance operations the 

conversion occurs. The agency requests comment on these and any 

other considerations for linkages between the federal plan and 

state plans that issue allowances in metric tons.18

The EPA also requests comment on expanding the scope of 

interstate trading to include linking states covered by the 

mass-based trading federal plan with any state that has an 

approved mass-based trading state plan meeting the proposed 

 

18 In this preamble all references to “tons” are short tons, unless 

otherwise noted.
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conditions for linkages and that uses an EPA-designated

allowance tracking system that is interoperable with an EPAadministered allowance tracking system. The EPA also 

requeststakes comment on allowing a registration 

requirementstate that has an approved mass-based trading state 

plan meeting the proposed conditions for linking to linkages and 

that uses an EPA-designated allowance tracking system, as noted 

above for the rate-based approach to register with the EPA, and 

after registration, to link with states covered by the massbased trading federal plan.

In the Clean Power Plan EGs, the EPA promulgated 

requirements that apply to an emissions budget trading state 

plan that includes non-affected EGU emission sources, to provide 

the opportunity for such a state plan to be potentially 

approvable for linking to other state plans. Those requirements 

include accounting adjustments for net import and export of 

allowances ( (see Clean Power Plan EGs, section VIII). In this 

proposed rule, the proposed approach to link from the mass-based 

trading federal plan to state plans could result in linking of 

the federal plan to state plans that include non-affected 

emission sources. The EPA requests comment on this proposed 

approach.

The EPA believes that a broad trading region provides 
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greater opportunities for cost-effective implementation of

reductions compared to trading limited to a smaller region. The 

proposed approach to interstate trading is intended to strike a 

reasonable balance between providing the opportunity for a wide 

interstate trading system while maintaining the integrity of the 

linked programs. The agency requests comment on the proposed 

approach to interstate trading linkages in the federal plans.

Whether the EPA ultimately finalizes rate-based or massbased federal plans, the agency believes that the ERC market and 

the allowance market would be competitive. The opportunities for 

interstate trading detailed above would reduce any potential for 

firms to exercise market power in the ERC market or allowance 

market. The EPA requests comment on this expectation of a 

competitive ERC market and a competitive allowance market, and 

comment on potential program design choices that could address 

any identified market power concern. The EPA intends to provide 

information to the market and the public, consistent with other 

trading programs that the agency administers, as detailed in 

sections IV and V of this preamble, for the rate-based and massbased approaches, respectively.

A transparent and well-functioning allowance or ERC market 

is an important element of a mass-based or rate-based trading 

program. EPA has over 20 years of experience implementing 
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emissions trading programs for the power sector and based on 

that experience, believes the potential or likelihood of market 

manipulation is fairly low. Nonetheless, the EPA is evaluating 

the options for providing oversight of the allowance or ERC 

markets that may be established through the final EGs and 

federal plans. This could include engaging with other federal 

and state agencies as appropriate, and potentially with third 

parties, in conducting market oversight. The agency requests 

comment on appropriate market monitoring activities, which may 

include tracking ownership of allowances or ERCs, oversight of 

the creation and verification of credits, and tracking market 

activity (e.g., transaction volumes and prices).

2. Interstate Effects and Addressing Potential Leakage and 

Interstate Effects

The final EGs recognized that emission reduction measures 

will likely have impacts across states and across categories of 

generation because of the dynamic flow of power on the regional 

grid (see final EGs Sec. VIII.L for a detailed discussion of 

interstate effects). In the final EGs, the EPA acknowledged that 

some amount of interstate movement of generation will inevitably 

be present and unavoidable and may affect how affected EGUs 

achieve the applicable CO2 emission performance rates or state 
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goals under a state plan. In fact, the final guidelines are 

premised in part on reductions due to the movement of generation 

from higher-emitting to lower-emitting affected EGUs. However, 

the risk of foregone emission reductions due to the movement of 

generation should be minimized. 

The final specify the concern of leakage, which is defined 

in Sec. VII.DThe final EGs specify the concern of leakage, which 

is defined in section VII.D of the final EGs as the potential of 

an alternative form of implementation (e.g., the rate-based and 

mass-based state goals) to spur increased emissions from new 

sources, beyond the emissions expected from new sources if 

existing EGUs were given create a larger incentive for affected 

EGUs to shift generation to new fossil fuel-fired EGUs relative 

to what would occur when the implementation of the BSER took the 

form of standards of performance in the form of incorporating 

the subcategory-specific emission performance rates.

representing the BSER.. The final EGs specified that mass-based 

plan approaches must address leakage, because the natureform of 

the mass goals created differingmay ultimately impact the 

relative incentives to run for affected existing EGUs generate 

and for new sources, which could result new sources running more 

and producing more emissions.emit at affected EGUs as opposed to 
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shifting generation to new sources, with potential implications 

for whether the mass goal implements or is consistent with the 

BSER and overall emissions from the sector. These circumstances 

are much less likely to be present under a rate-based plan 

approach, where boththe form of the goal ensures sufficient 

incentive to affected existing EGUs to generate and new sources 

face thus avoid leakage, similar incentives to run.to the CO2

emission performance rates. By requiring mass-based plan 

components that address leakage, the final EGs ensure that mass 

goals are an equivalent alternative to the subcategories CO2

emission performance rates and rate-based goals. Sec.are thus an 

equivalent expression of the BSER. Section VII.D of the final 

EGs details the requirement for addressing leakage and why it is 

needed, and Sec.section VIII.J of the final EGs specifies 

options for mass-based state plan components that address 

leakage. We are proposing, as part of the mass-based approach 

under the federal plan and model rule, to implement allowance

allocation approaches to address leakage, specifically through 

establishing an output-based allocation set-aside and a setaside that encourages the installation of RE. These proposed 

strategies are detailed in Sec.section V.D of this 

proposalpreamble.
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There are other various ways that the final EGs and the 

federal plan and model rule proposal act to avoid other types of

foregone reductions, including through the particular structure 

of the subcategorized CO2 performance rates, state goals and 

compliance accounting, that deemphasize the differences between 

states. Additionally, there are restrictions to avoid forgone 

emissions, including the condition that jurisdictions under the 

rate-based federal plan, and states that seek to trade with 

rate-based federal plan jurisdictions, must used the 

subcategorized CO2 performance rates. This eliminates differing 

incentives between states in rate-based ERC issuance and 

trading, as discussed in final EGs Sec. VIII.L. In the final 

EGs, the EPA also discussed the concern that CO2 emissions 

reductions would be eroded in situations where an affected EGU

in a rate-based state counts the MWh from measures located in a 

mass-based state, but the generation from that measure acts 

solely to serve load in the mass-based state. In that scenario, 

expected CO2 emission reduction actions in the rate-based state 

are foregone as a result of counting MWh that resulted in CO2

emission reductions in a mass-based state. The proposed ratebased approach, in accordance with the final guidelines, 

restricts ERC issuance for any emission reduction measures 

located in a mass-based state, except for RE. RE measures 
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located in a state with a mass-based state plan can only be 

approved for ERC issuance for use by a state under a rate-based 

federal plan if it can be demonstrated that that load-serving 

entities in the rate-based state have contracted for the 

delivery of the RE generation that occurs in a mass-based state 

to meet load in a rate-based state. As part of this federal 

plan, we are proposing that this can be demonstrated through the 

provision of a power delivery contract or power purchase 

agreement in which an entity in the rate-based state contracts 

for the supply of the MWhs in question and providing

documentation that the electricity was treated as comparable to 

a generation resource used to serve regional load that included 

the rate-based state. This demonstration must be included as 

part of the project application for ERC issuance to the EPA or 

its agent from the RE provider in the mass-based state. Once the 

project is approved, subsequent applications for issuance of 

credit to the EPA will need to reference that the megawatthoursMWh submitted are associated with that contractual 

arrangement with the mass-based RE provider. The EPA requests 

comment on this approach. It should also be noted that we are 

proposing that under the proposed mass-based approach, if RE 

located in a mass-based state receives mass-based set-aside 

allowances for any generation, that generation is not eligible 
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to be issuedERCsissued ERCs in a rate-based state.

The EPA requests comment on the proposed treatment of 

leakage and of interstate effects under both the proposed ratebased federal plan approach and the proposed mass-based federal 

plan approach, and as part of the corresponding proposed model 

rules. 

3. Provisions to Encourage Early Action

&&&Placeholder while this section being worked on 

offline&&&

The EPA outlined and initiated the Clean Energy Incentive

Program (CEIP) in the final EGs (see section VIII.B.2 of the final 

EGs). The program is designed to incentivize investment in certain 

types of RE projects, as well as demand-side energy efficiency 

(EE) projects implemented in low-income communities. These 

projects must commence construction after the date of submission 

of a final state plan to the EPA, or after September 6, 2018 for 

those states on whose behalf the EPA is implementing the federal 

plan, and will receive incentives for the MWh they generate or the 

end-use energy demand reductions they achieve during 2020 and/or

2021. The CEIP also provides an additional incentive to drive 

investment in demand-side EE projects implemented in low-income 

communities. The EPA proposes to apply the CEIP in all states 
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subject to either a rate-based or mass-based federal plan. The 

EPA’s proposed approaches to implementing the program in the ratebased and mass-based federal plans are detailed in sections IV and 

V of this preamble, respectively. 

B. Inventory of Emissions

Fossil fuel-fired electric utility generating units (EGUs)

are by far the largest emitters of GHGs among stationary sources 

in the U.S., primarily in the form of CO2, and among fossil fuelfired EGUs, coal-fired units are by far the largest emitters. 

This section describes the amounts of these emissions and places 

these amounts in the context of the U.S. Inventory of Greenhouse 

Gas Emissions and Sinks19 (the U.S. GHG Inventory). 

The EPA implements a separate program under 40 CFR part 98 

called the Greenhouse Gas Reporting Program20 (GHGRP) that requires 

emitting facilities over threshold amounts of GHGs to report their 

emissions to the EPA annually. Using data from the GHGRP, this 

 

19 “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 –

2013”, Report EPA 430-R-15-004, United States Environmental 

Protection Agency, April 15, 2015.

http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.

html

20 U.S. EPA Greenhouse Gas Reporting Program Dataset, see

http://www.epa.gov/ghgreporting/ghgdata/reportingdatasets.html

Formatted: Indent: First line: 0"
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section also places emissions from fossil fuel-fired EGUs in the 

context of the total emissions reported to the GHGRP from 

facilities in the other largest-emitting industries. 

The EPA prepares the official U.S. GHG Inventory to comply 

with commitments under the United Nations Framework Convention on 

Climate Change (UNFCCC). This inventory, which includes recent 

trends, is organized by industrial sectors. It provides the 

information in Table 2 below3 of this preamble, which presents 

total U.S. anthropogenic emissions and sinks21 of GHGs, including 

CO2 emissions, for the years 1990, 2005, and 2013.

Table 23. U.S. GHG Emissions and Sinks by Sector (Million Metric 

Tons Carbon Dioxide Equivalent (MMT CO2 Eq.))22

SECTOR 1990 2005 2013

Energy23

 

5,290.5

 

6,273.6

 

5,636.6

Industrial Processes 342.1 367.4 359.1

 

21 Sinks are a physical unit or process that stores GHGs, such as 

forests or underground or deep sea reservoirs of CO2.

22 From Table ES-4 of “Inventory of U.S. Greenhouse Gas Emissions 

and Sinks: 1990 – 2013”, Report EPA 430-R-15-004, United States 

Environmental Protection Agency, April 15, 2015.

http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.

html 

23 The energy sector includes all greenhouse gases resulting from 

stationary and mobile energy activities, including fuel combustion 

and fugitive fuel emissions.
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and Product Use

Agriculture 448.7 494.5 515.7

Land Use, Land-Use 

Change and Forestry

 

13.8 25.5 23.3 

Waste 206.0 189.2 138.3

Total Emissions 6,301.1 7,350.2

 

6,673.0

Land Use, Land-Use 

Change and Forestry 

(Sinks)

 

(775.8) (911.9) (881.7)

Net Emissions (Sources 

and Sinks)

 

5,525.2 6,438.3

 

5,791.2

Total fossil energy-related CO2 emissions (including both 

stationary and mobile sources) are the largest contributor to total 

U.S. GHG emissions, representing 77.3 percent of total 2013 GHG 

emissions.24 In 2013, fossil fuel combustion by the utility power 

sector –- entities that burn fossil fuel and whose primary business 

is the generation of electricity –- accounted for 38.3 percent of 

 

24 From Table ES-2 “Inventory of U.S. Greenhouse Gas Emissions and 

Sinks: 1990 – 2013”, Report EPA 430-R-15-004, United States 

Environmental Protection Agency, April 15, 2015.

http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.

html.
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all energy-related CO2 emissions.25 Table 3 below4 of this preamble

presents total CO2 emissions from fossil fuel-fired EGUs, for years 

1990, 2005, and 2013.

Table 34. U.S. GHG Emissions from Generation of Electricity from 

Combustion of Fossil Fuels (MMT CO2)26

In addition to preparing the official U.S. GHG Inventory to 

present, which represents comprehensive total U.S. greenhouse 

gasGHG emissions and complycomplies with commitments under the 

 

25 From Table 3-1 “Inventory of U.S. Greenhouse Gas Emissions and 

Sinks: 1990 – 2013”, Report EPA 430-R-15-004, United States 

Environmental Protection Agency, April 15, 2015.

http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.

html.

26 From Table 3-5 “Inventory of U.S. Greenhouse Gas Emissions and 

Sinks: 1990 – 2013”, Report EPA 430-R-15-004, United States 

Environmental Protection Agency, April 15 2015.

http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.

html.

GHG EMISSIONS 1990 2005 2013

Total CO2 from fossil fuelfired EGUs 

1,820.8 

 

2,400.9 

 

2,039.8 

 - from coal

 

1,547.6 

 

1,983.8

 

1,575.0

 - from natural gas

 

175.3 

 

318.8 441.9 

 - from petroleum

 

97.5 

 

97.9 22.4
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UNFCCC, the EPA collects detailed GHG emissions data from the 

largest emitting facilities in the U.S. through its Greenhouse Gas 

Reporting Program (GHGRP).GHGRP. Data collected by the GHGRP from 

large stationary sources in the industrial sector show that the 

utility power sector emits far greater CO2 emissions than any other 

industrial sector. Table 4 below5 of this preamble presents total 

GHG emissions in 2013 for the largest emitting industrial sectors 

as reported to the GHGRP. As shown in Table 34 and Table 45 of 

this preamble, respectively, CO2 emissions from fossil fuel-fired 

EGUs are nearly three times as large as the total reported GHG 

emissions from the next ten largest emitting industrial sectors in 

the GHGRP database combined.

Table 45. Direct GHG Emissions Reported to GHGRP by Largest 

Emitting Industrial Sectors (MMT CO2e)27

 

27 U.S. EPA Greenhouse Gas Reporting Program Dataset as of August 

18, 2014. http://ghgdata.epa.gov/ghgp/main.do.

Industrial sector 2013

Petroleum Refineries 176.7 

Onshore Oil & Gas Production 94.8

Municipal Solid Waste Landfills 93.0 

Iron & Steel Production 84.2 

Cement Production 62.8

Natural Gas Processing Plants 59.0

Petrochemical Production 52.7

Hydrogen Production 41.9

Underground Coal Mines 39.8
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C. Affected EGUs

For the CPP EGsClean Power Plan and this federal plan, an 

affected EGU is any steam generating unitSGU, IGCC, or 

stationary combustion turbine that was in operation or had 

commenced construction as of January 8, 2014,28 and that meets 

the following criteria, which differ depending on the type of 

unit. To be an affected EGU, such a unit, if it is a steam 

generating unitSGU or IGCC, 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). If such a unit is a stationary 

combustion turbineSCT, the unit must meet the definition of a 

combined cycle or combined heat and powerCHP combustion turbine, 

serve a generator capable of selling greater than 25 MW to a 

utility power distribution system, and have a base load rating 

of greater than 260 GJ/h (250 MMBtu/h). 

 

28 Under section 111(a) of the CAA, determination of affected 

sources is based on the date that the 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).

Food Processing Facilities 30.8
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When considering and understanding applicability, the 

following definitions may be helpful. Simple cycle combustion 

turbine means any stationary combustion turbine which does not 

recover heat from the combustion turbine engine exhaust gases 

for purposes other than enhancing the performance of the 

stationary combustion turbine itself. Combined cycle combustion 

turbine means any stationary combustion turbineSCT which 

recovers heat from the combustion turbine engine exhaust gases 

to generate steam that is used to create additional electric 

power output in a steam turbine. Combined heat and power (CHP)

combustion turbine means any stationary combustion turbineSCT

which recovers heat from the combustion turbine engine exhaust 

gases to heat water or another medium, generategenerates steam 

for useful purposes other than exclusively for additional 

electric generation, or directly uses the heat in the exhaust 

gases for a useful purpose.

We note that certain affected EGUs are exempt from 

inclusion in a state plan and this federal plan. Affected EGUs 

that may be excluded under the EGs are those that (1) Are 

subject to subpart TTTT as a result of commencing modification 

or reconstruction; (2) steam generating unitsare SGUs or IGCC 

units that are currently and always have been subject to a 

federally enforceable permit limiting net-electric sales to one-
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third or less of its potential electric output or 219,000 MWh or 

less on an annual basis; (3) are non-fossil units (i.e., units 

that are capable of combusting 50 percent or more 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) are 

stationary combustion turbines that are not capable of 

combusting natural gas (i.e., not connected to a natural gas 

pipeline); (5) are a combined heat and power unit CHP units that 

are subject to a federally enforceable permit limiting, or have 

historically limited, annual net electric sales to a utility 

power distribution system to the product of the design 

efficiency and the potential electric output or 219,000 MWh 

(whichever is greater) or less; (6) serve a generator along with 

other steam generating unitSGU(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 unitSGU, IGCC, or stationary combustion 

turbine) is 25 MW or less; (7) are a municipal waste combustor 

unit subject to subpart Eb of 40 CFR part 60; or (8) are a 

commercial or industrial solid waste incineration unit that is 
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subject to subpart CCCC of 40 CFR part 60.29

The EPA is also taking comment on an alternative compliance 

pathway that could be available to units under a mass based 

approach. The ways that the approach could be implemented are 

further outlined in the Alternative Compliance Pathway for Units

that Agree to Retire Before a Certain Date TSD. Under this 

approach, two basic requirements would need to be met. The first 

is that the unit would have to take a commitment that it would 

retire on a date on or before December 31, 2029. The second is 

that the unit would have to demonstrate that it will take an 

enforceable emission limitation that would assure that the 

overall state emission goal is met. The TSD explores ways that 

this approach could be implemented, including ways that the 

enforceable emission limitation could be calculated and 

 

29 We had proposed in the CPP EGs that affected EGUs were those 

existing source fossil fuel-fired EGUs that met the applicability 

criteria for coverage under the final GHG standards for new fossil 

fuel-fired EGUs being promulgated under CAA section 111(b). 

However, we are finalizing in the EGs that states need not include 

certain units that would otherwise meet the CAA section 111(b) 

applicability in this CAA section 111(d) EGs. These include simple 

cycle turbines, certain non-fossil units, and certain CHP units. 

The final CAA section 111(b) standards include applicability 

criteria for simple cycle combustion turbines, for reasons 

relating to implementation and minimizing emissions from all 

future combustion turbines.
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implemented. The EPA requests comment on whether this approach 

should be available for all units or limited to small units 

(e.g. less than 100 MW nameplate capacity). EPA is also taking 

comment on whether and how such an approach could be included 

under a rate-based approach.

The applicability of this proposed federal plan follows the 

same applicability criteria as the final EGs. The rationale for 

these criteria is provided at &&&citation to EGs.in section IV.D 

of the Clean Power Plan. We are not reopening the criteria or 

rationale here. 

In the federal plan Affected EGU Technical Support Document 

(TSD,), the EPA lists all applicable affected EGUs according to 

our records from the National Electric Energy Data System 

(NEEDS), Energy Information Administration (EIA), and comments 

from the CPP. In this TSD, each affected EGU is assigned its 

proposed applicable standards if a federal plan were to be 

promulgated for that affected EGU at any time. The EPA requests 

comments and updates to this list of affected units. Section 

VI.C of the CPPfinal EGs describes the data used in setting the 

standards and how an inventory of affected units has been 

compiled.

D. Compliance Schedule

In accordance with the schedule set out in the EGs, the 
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federal plan is proposed to be implemented in a phased approach. 

The first period, corresponding to the interim period in the EG, 

is proposed to run from beginning of calendar year 2022 until 

end of calendar year 2029 (January 1, 2022 to December 31, 

2029). The final period would run from beginning of calendar 

year 2030 (January 1, 2030) indefinitely into the future. The 

first period is proposed to be comprised of three “compliance

periods,” set by calendar year. The first compliance period will 

be from January 1, 2022 to midnight, December 31, 2024 (three3

calendar years). The second compliance period will be from 

January 1, 2025 to midnight, December 31, 2027 (three3 calendar 

years). The third compliance period will be from January 1, 2028 

to midnight, December 31, 2029 (two2 calendar years).

Under the EGs, midnight, December 31, 2029 marks the end of 

the interim period, and the beginning of the final period. The 

EPA proposes that the compliance periods in the final period 

will each be two2 calendar years. Thus, the first compliance 

period after 2030 would be from January 1, 2030 to midnight, 

December 31, 2031. The second compliance period would be from 

January 1, 2032 to midnight, December 31, 2033. This would 

repeat accordingly unless changed by the EPA through a revision 
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to the federal plan or other action.30

The EPA recognizes that the compliance periods provided for 

in this rulemaking are longer than those historically and 

typically specified in CAA rulemakings. As reflected in longstanding CAA precedent, “[t]he time over which [the compliance 

standards] extend should be as short term as possible and should 

generally not exceed one month.” See e.g., June 13, 1989 

Guidance on Limiting Potential to Emit in New Source Permitting 

and January 25, 1995 Guidance on Enforceability Requirements for 

Limiting Potential to Emit through SIP and §112 Rules and 

General Permits. The EPA determined that the longer compliance 

periods provided for in this rulemaking are acceptable in the 

context of this specific rulemaking because of the unique 

characteristics of this rulemaking, including that CO2 is longlived in the atmosphere, and this rulemaking is focused on 

performance standards related to those long-term impacts.

Prior to the beginning of the first compliance period in 

2022, the agency intends to establish the infrastructure for 

operating a federal trading program and to work closely with 

affected EGUs in the states where the federal plan is 

promulgated prior to the start of the first compliance period in 

 

30 This schedule would be the same under either a rate- or massbased approach. 
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2022. We request comment on whether it would be possible to 

grant, on a case-by-case basis, certain affected EGUs, 

particularly small entities, additional time to come into 

compliance, and to request additional input from the public as 

to the design of such flexibility that would be compatible with 

the emission guidelinesEGs and a federal plan that implements a 

trading system.

The EPA recognizes that it is important to ensure a degree 

of liquidity in compliance instruments in either of the proposed 

trading approaches, while also maintaining the stringency 

required by the final EGs. A number of aspects of the rate-based 

and mass-based programs would assist with this, including 

allocation methods or rules, mechanisms to place allowances or 

credits into the market relatively early, requirements for 

public transparency of information related to allowance, or 

credit issuance, tracking, transfers and holdings. The EPA 

solicits comment on other approaches to ensure market liquidity

while continuing to meet the stringency of the final EGs.

E. Addressing Reliability Concerns

The proposed federal plan has been designed to ensure that, 

to the greatest extent possible, implementation would not 

interfere with the power sector’s ability to maintain electric 
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reliability.31 Like the EGs, the federal plan provides a long 

planning horizon and implementation period. In addition the 

federal plan allows affected EGUs to obtain tradable allowances 

and credits to meet obligations which assures that reliability 

can be maintained without disruption to the electricity system.

There are many features of the electricity system that 

ensure that electric system reliability will be maintained. For 

example, in the Energy Policy Act of 2005, Congress added a 

section to the Federal Power Act to make reliability standards 

mandatory and enforceable by FERCthe Federal Energy Regulatory 

Commission (FERC) and the North American Electric Reliability 

Corporation (NERC), the Electric Reliability Organization which 

FERC designated and oversees. Along with its standards 

development work, NERC conducts annual reliability assessments 

via a 10-year forecast and winter and summer forecasts; audits 

owners, operators and users for preparedness; and educates and 

trains industry personnel. Numerous other entities such as FERC, 

Department of Energy (DOE,), state public utility commissions 

(PUCs, ), independent system operators and regional transmission 

 

31 The EPA evaluated certain aspects of electric reliability in the context of 

modeling projections for the final Clean Power Plan, and that evaluation is 

described in the “Resource Adequacy and Reliability Analysis TSD” for that 

rulemaking, a copy of which is also included in the docket for this rulemaking.
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organizations (ISOs/RTOs,), and other planning authorities also 

consider the reliability of the electric system. There are also 

numerous remedies that are routinely employed when there is a 

specific local or regional reliability issue. These include 

transmission system upgrades, installation of new generating 

capacity, calling on demand response, and other demand-side 

actions. 

Additionally, planning authorities and system operators 

constantly consider, plan for, and monitor the reliability of 

the electricity system with both a long-term and short-term 

perspective. Over the last century, the electric industry’s 

efforts regarding electric system reliability have become 

multidimensional, comprehensive, and sophisticated. Under this 

approach, planning authorities plan the system to assure the 

availability of sufficient generation, transmission, and 

distribution capacity to meet system needs in a way that 

minimizes the likelihood of equipment failure.32 Long-term system

planning happens at both the local and regional levels with all 

segments of the electric system needing to operate together in 

 

32 Casazza, J. and Delea, F., Understanding Electric Power Systems: 

An Overview of the Technology, the Marketplace, and Government 

Regulations, IEEE Press, at 160 (2010).
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an efficient and reliable manner. In the short-term, electric 

system operators operate the system within safe operating 

margins and work to restore the system quickly if a disruption 

occurs.33 Mandatory reliability standards apply to how the bulk 

electric system is planned and operated. For example, 

transmission operators and balancing authorities have to 

develop, maintain, and implement a set of plans to mitigate 

operating emergencies.34

The EPA’s approach in this proposed federal plan builds on 

the foundation provided in the EG’s determination of BSER to 

ensure that the final federal plan, like the final EG, does not 

interfere with the industry’s ability to maintain reliability of 

the nation’s electricity supply. First, the federal plan, like 

the EG, provides more than six6 years before reductions are 

required and an eight8-year period from 2022 to 2029 to meet 

interim goals. This allows time for planning and steady,

measured implementation.

Second, the federal plan is a market-based trading program 

which will allow affected EGUs the opportunity to buy and sell 

 

33 Id.

34 NERC Reliability Standard EOP-001-2.1b — Emergency Operations 

Planning, available at 

http://www.nerc.net/standardsreports/standardssummary.aspx.
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emissions credits or allowances as well as bank them. The EPA’s 

proposed federal plan includes two alternative approaches;: a 

mass-based trading program and a rate-based trading program.

Trading programs of both types have many positive attributes.

Among them is that they help to ensure that imposition of the 

federal plan will not interfere with the industry’s ability to 

maintain the reliability of the nation’s electricity supply. 

Such a program does not restrict unit-level operational 

decision-making beyond requiring units to hold a sufficient 

number of tradable permits (e.g., allowances or ERCs) to cover 

emissions. It, therefore, inherently allows for unit level 

operational flexibility to facilitate the maintenance of 

reliability and makes the program enormously resilient. If a 

unit finds it needs to run more than anticipated, the marketbased compliance system provides a way for the EGU to meet its 

generation needs while it maintains compliance with the federal 

plan.

Third, just as we have required the states to do in 

developing state plans, the EPA is considering reliability as a 

part of developing this federal plan. For example, the EPA will 

consult with planning authorities. The EPA will work with the 

ISO/RTO Council to convene a face-to-face meeting for planning 

authorities with the EPA during the comment period to discuss 
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any concerns or other feedback on the federal plan from those 

entities. This meeting will help to ensure that the EPA is 

taking into consideration any concerns about the relationship of 

this rulemaking to the ability of the industry to maintain 

electric reliability across the country as we finalize the 

federal plan. It will give the planning authorities an 

opportunity to hear directly from the EPA how the federal plan

is designed and gives the planning authorities an opportunity to 

voice concerns and ask questions. This will help inform comments 

that planning authorities may submit to the docket.

In the final Clean Power PlanCPP EGs, the EPA laid out the 

availability of a reliability safety valve that could be used if 

an unanticipated catastrophic emergency caused a conflict 

between maintenance of electric reliability and inflexible 

requirements that a state plan might impose on an affected EGU 

or EGUs. Under the federal plan, inflexible requirements are not 

imposed on specific plants. Rather as explained earlier, the 

very nature of the federal plan, in which affected EGUs can 

obtain allowances or credits if needed, supports reliability. 

Therefore, a reliability safety valve for the federal plan is 

not needed. The EPA invites comments on this aspect of the 

proposed federal plan.

The EPA, Department of Energy (DOE) and FERC have agreed to 
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coordinate efforts to help ensure continued reliable electricity 

generation and transmission during the implementation of the 

final EGEGs and the final federal plan in any state that does 

not have an approved state plan. The three agencies have 

developed a coordination strategy that reflects their joint 

understanding of how they will work together to monitor 

implementation. The three agencies will work together to monitor 

implementation, share information and resolve any difficulties 

that may be encountered.

The EPA is not proposing to include an allowance set-aside, 

or similar mechanism in a rate-based approach, to address 

reliability issues in the federal plan; however, we request comment 

on including such a set-aside in the context of a mass-based 

approach. The EPA requests comment specifically on creation of an 

allowance set-aside for the purpose of making allowances available 

in emergency circumstances in which an affected EGU was compelled 

to provide reliability critical generation and demonstrated that 

a supply of allowance needed to offset its emissions was not 

available. 

The set-aside would be in addition to the proposed set-asides 

that are detailed in section V.D in this preamble. The EPA would 

set aside allowances in each state under the mass-based federal 

plan, and if a reliability issue is perceived by the EPA, DOE, and 
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FERC coordinated monitoring process discussed above, the EPA would 

distribute allowances from the set-aside to support affected EGUs 

during or after an unforeseen, emergency reliability event. If 

there were unused allowances remaining in the set-aside, then the 

EPA would distribute them to affected EGUs pro rata based on the 

allocation approach that is detailed in section V.D. of this 

preamble. The EPA requests comment on all elements of such an 

approach, including what events would trigger the need for 

allowances from the reliability set-aside; eligibility criteria to 

receive the set-aside allowances; the size of the set-aside; and 

the timing of distribution of allowances from the reliability setaside. Additionally, the EPA requests comment on how a reliability 

“set-aside” approach could be implemented in the rate-based 

federal plan.

As detailed later in this preamble, the EPA proposes in the 

federal plan to implement a Clean Energy Incentive ProgramCEIP, 

which was established in the EGs to reward investment in certain 

clean energy projects that achieve MWh results during 2020 and 

20212020 and/or 2021 (see sections IV and V of this preamble for 

the proposed approach to implement this incentive program in the 

rate-based and mass-based federal plans, respectively). 

Implementation of the Clean Energy Incentive Program in the federal 

plans would create ERCs and allowances before 2022, allowing for 
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creation of banks that could be used in the event of an unforeseen, 

emergency reliability issue. The EPA requests comment on the 

potential for these banks of ERCs and allowances to support 

reliable electricity generation and transmission to be utilized in 

the event of this kind of reliability emergency.

F. Worker Certification

In the EGs, the EPA suggested that to ensure that emission 

reductions are realized, it is important that construction, 

operations and other skilled work undertaken pursuant to state 

plans is performed to specifications, and is effective, safe, 

and timely. The EPA asks for comments as to whether the federal 

plan should encourage EGUs to ask for a demonstration that the 

work undertaken under a federal plan is performed by a 

proficient workforce. A good way to ensure such a workforce is 

to require that workers have been certified by: (1) An 

apprenticeship program that is registered with the U.S. DOL, 

Office of Apprenticeship or a state apprenticeship program 

approved by the DOL; (2) a skill certification aligned with the 

U.S. DOE Better Building Workforce Guidelines and validated by a 

third party accrediting body recognized by DOE; or (3) other 

skill certification validated by a third party accrediting body.
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G. Remaining Useful Lives and Potential for “Stranded Assets”

Section 111(d)(2) of the CAA provides, “In promulgating a 

standard of performance under a plan prescribed under this 

paragraph, the Administrator shall take into consideration, 

among other factors, remaining useful lives of the sources in 

the category of sources to which such standard applies.” 42 

U.S.C. 7411(d)(2). This language tracks similar language in CAA

section 111(d)(1) with respect to state plans. In the final EGs, 

we explained how the Guidelines permit states in applying a 

standard of performance in their state plans to consider the 

remaining useful life of a facility. We determined that it was 

appropriate to specify that the general variance provisions in 

40 CFR 60.24(f) should not apply to the class of affected 

facilities covered by these Guidelines. &&&citation. We 

concluded that facility-specific factors and in particular, 

remaining useful life, do not justify a state making further 

adjustments to the performance rates or aggregate emission goal 

that the Guidelines define for affected EGUs in a state and that 

must be achieved by the state plan. 

Because the Guidelines do not allow for states to deviate 

from state goals based on remaining useful life, the EPA does 

not believe such goal adjustments are necessary or appropriate 

in the federal plan either. Nonetheless, this does not obviate 
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the requirement that the EPA itself, in the design of its 

federal plan, consider, among other factors, the remaining 

useful lives of the affected facilities. The agency therefore 

proposes the following analysis of this factor.35

Congress added the “remaining useful lives” factor to CAA 

section 111(d)(2) in the 1977 CAA Amendments. Congress did not 

provide in the statute any direction on how or to what degree 

“remaining useful lives” of facilities subject to a section 

111(d) federal plan is to be considered. As discussed in the 

preamble to the final EGs, Congress’ intent in enacting the 

provision was to allow for older facilties with short remaining 

useful lives to not be required to install capital-intensive 

pollution control devices to meet emission standards that would 

 

35 We note that the preamble and supporting materials for the EGs 

discuss a related concern raised by some stakeholders, which is 

whether the EGs could result in widespread “stranded assets” as a 

direct result of the rule. As explained there, we believe this 

concern is distinct from the “remaining useful lives” factor in 

CAA section 111(d)(1), and for the same reasons, believe it is 

distinct from the factor Congress directed the agency to consider 

in CAA section 111(d)(2). Nonetheless, we undertook analysis in 

the final EGs of whether and to what extent there may be a “stranded 

asset” concern. See memorandum to Clean Power Plan Docket EPA-HQOAR-2013-0602 titled “Stranded Assets Analysis” dated July 2015. 

We believe that analysis demonstrates that this is not likely to 

be a widespread issue under the federal plan either. 
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only be used for a short period of time before a plant ceased 

operation. A House of Representatives report on a predecessor 

bill to the enacted statute stated, “Older plants with 

relatively short remaining useful lives might have chosen to 

cease operation if the only means of emission limitation 

available to meet emission limits were pollution control 

technology.” H. Report 94-1175, at 159 (1976) (emphasis added). 

This language is probative of the fact that Congress viewed 

“remaining useful lives” as a consideration for facilities with 

relatively little remaining useful life. We are confident the 

proposed federal plan will not force costly pollution control 

investments at older plants with short remaining useful lives.

Further, the statute provides that this factor is one 

“among other factors” that the agency is to consider in 

promulgating a standard of performance. Congress provided no 

guidance in the statute as to what those other factors could be. 

The inclusion of unspecified factors that the agency may 

determine for itself to consider, along with the use of the term 

“consider,” highlights that Congress intended to give the agency 

a substantial degree of discretion in determining how the 

“remaining useful lives” factor is considered. The statute does 

not require, and Congress did not intend, that this 

consideration mandate the agency to prevent all premature 
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retirements of affected EGUs, to impose no emission requirements 

on older affected EGUs, or to ensure that profitability is 

maintained at all times for all affected EGUs. Congress knew how 

to explicitly exempt older plants from CAA requirements at the 

time of the 1977 Amendments. For example, Congress excluded 

plants in existence before August 7, 1977 from the 

preconstruction requirements of the PSD/non-attainment new 

source review (NSR) program, see CAA section 165(a). And in CAA 

section 169A related to visibility impairment in federal class I 

areas, Congress excluded from applicability units that began

operation before August 7, 1962. 42 U.S.C. 7491(b)(2)(A). In CAA

section 111(d) Congress did not set any such specific criteria. 

Rather it directed the agency to “consider” the remaining useful 

lives of facilities, among other factors.

This view also accords with past agency practice in 

implementing a similar provision. In the 1977 Amendments, 

Congress listed “remaining useful life” as a factor for 

consideration in the visibility program under section 169A. 42 

USC 7491. The “remaining useful life of the source” is one of 

several enumerated factors that the state or the EPA is to 

consider in determining the best available retrofit technology 

(BART) for a particular source. Consistent with congressional 

purpose, the EPA has implemented this factor in the regional 
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haze program for many years through the BART guidelines, in 

appendix Y to 40 CFR part 51. The BART Guidelines provide: 

The “remaining useful life” of a source, if it 

represents a relatively short time period, may affect the 

annualized costs of retrofit controls. ... If the remaining 

useful life will clearly exceed th[e] time period [for 

amortization based on the type of control], the remaining 

useful life has essentially no effect on control costs and 

on the BART determination process. Where the remaining 

useful life is less than the time period for amortizing 

costs, you should use this shorter time period in your cost 

calculation.

40 CFR part 51, App.appendix Y, section IV.D.4.k. In the 

agency’s view, this approach to “remaining useful life” aligns 

with congressional intent and informs our view of how the 

“remaining useful lives” factor should be considered under this 

CAA section 111(d) federal plan. The key consideration is 

whether the time period associated with amortizable costs of 

compliance will exceed the remaining useful lives of the sources

in question.

Consistent with legislative intent and past agency 

practice, we propose that the federal Plan adequately considers

”remaining useful lives” of affected EGUs by providing for 

trading and other flexibilities authorized in the EGs. To 

summarize, these include: relatively long periods for affected 

EGUs to come into compliance, the ability to credit early 

action, the use of emissions trading, the use of multi-year 
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compliance periods, and the ability to link to other federal or 

state plans to create larger emissions markets. The federal plan 

is proposed to include a Clean Energy Incentive Program as 

provided for in the EGs, which will credit early action and ease 

compliance in the firstinitial years of the program. These tools 

will create economic incentives that reward over-performance of 

some affected EGUs, and allow others to simply acquire credits 

or allowances to comply with their emission standard, thereby

avoiding the need for installation of costly pollution controls 

at sources with a short remaining life.

Thus, the proposed federal plan is designed in such a way 

that it adequately, and inherently, takes into account the 

remaining useful lives of affected EGUs. It provides substantial 

compliance flexibility, including means of avoiding the need to 

make extensive capital investments in control technologies that 

could not be recouped during the remaining useful lives of a 

facility.36 The design of the federal plan as a form of emission 

 

36 Because we believe that this is the case for all facilities 

through the basic design of the federal plan, we also can confirm, 

in line with the EGs, that the availability of variances from the 

emission standards is unnecessary in the federal plan. Under the 

general framework regulations, facility-specific variances from an 

otherwise applicable standard of performance have been potentially 

available under the application process in 40 CFR 60.27(e)(2), 
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trading provides individual affected EGUs the flexibility to 

make cost-conscious compliance choices. This flexibility avoids 

or substantially diminishes any likelihood that compliance will 

be a physical impossibility or result in unreasonable costs.

By relying on either rate- or mass-based emission trading, 

the proposed federal plan capitalizes on the inherent 

flexibility available through market-based techniques. In 

effect, under a trading program with repeating compliance 

periods, a facility with a short remaining useful life has a 

total outlay that is proportionately smaller than a facility 

with a long remaining useful life, simply because the first 

facility would need to comply for fewer compliance periods and 

would need proportionately fewer ERCs or allowances than the 

second facility. Buying ERCs or allowances as a compliance 

method could avoid excessive up-front capital expenditures that 

 

which incorporates the factors provided in 40 CFR 60.24(f) for 

states. Consistent with our view that the federal plan adequately 

considers remaining useful lives, and for the same reasons, the 

need for facility-specific variances under the circumstances of 

60.24(f) (unreasonable costs of controls, physical impossibility 

of installation of necessary control equipment, or other factors 

that make longer compliance times or less stringent standards 

significantly more reasonable) is not expected to arise, and thus, 

the agency proposes to make 40 CFR 60.27(e) inapplicable in this 

federal plan.
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might be unreasonable for facilities with short remaining useful 

lives, and therefore addresses the consideration of “remaining 

useful lives.” Buying ERCs or allowances as a compliance method 

also would reduce the potential for stranded assets.

In addition, the timing of the federal plan limits the 

immediate costs of compliance, particularly for facilities that 

have useful lives ending before 2022, but also for facilities 

that have useful lives ending before 2030. There are no 

compliance obligations for affected EGUs under this federal plan 

until 2022, when the first compliance period begins. At that 

point, the agency is following the glide path provided for in 

the EGs, which begins with relatively higher emission targets 

that will slowly strenghten over the interim performance period 

from 2022-2029 through three multi-year compliance periods. The 

final, most stringent, compliance obligation does not begin 

until 2030.

Further, unlike state plans that can be more stringent 

under CAA section 116, the federal plan is no more stringent 

than the EGs, and, as explained in the EGs, the Guidelines 

reflect a reasonable, rather than a maximum possible, 

implementation level for each building block in order to 

establish overall goals that are achievable. As discussed in the 

EG , &&&cite, the BSER determined an average level of emissions 
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achievable by groups of EGUs, rather than for an individual EGU.

In considering the remaining useful lives of facilities under a 

federal plan, the EPA believes this approach to setting the 

emission standards, coupled with the ability to trade, 

adequately accounts for remaining useful lives of facilities. In 

essence, it allows the facilities to comply with the federal 

plan through the purchase or acquisition of ERCs or allowances, 

and to avoid the need to make costly investments in control 

technology for plants that have short remaining useful lives.37

For these reasons, we believe the federal plan adequately 

considers “remaining useful lives.” We invite comment on our 

consideration of facilities’ “remaining useful lives” in the 

federal plan.

H. Implications for Other EPA Programs and Rules

1. Title V Permitting

a. Permitting Requirements

Under the proposed federal plan, title V permits for

sources with affected EGUs will need to include any new 

 

37 In addition, the ability to generate ERCs for sale or to sell 

unneeded emission allowances (depending on whether in a rate- or 

mass-based system) may give some affected EGUs an economic 

incentive to take measures to reduce emissions that otherwise would 

have been uneconomical.
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applicable requirements that the plan places on the affected 

EGUs. The EPA, however, is not proposing any permitting 

requirements independent of those that would be required under 

title V of the Clean Air ActCAA and the regulations implementing 

title V, 40 CFR parts 70 and 71.38 All major stationary sources 

of air pollution and certain other sources are required to apply 

for title V operating permits that include emission limitations 

and other conditions as necessary to assure compliance with 

applicable requirements of the CAA, including the requirements 

of an applicable CAA section 111(d) state plan or federal plan. 

CAA §§sections 502(a) and 504(a), 42 U.S.C. 7661a(a) and 

7661c(a). The “applicable requirements” that must be addressed 

in title V permits are defined in the title V regulations, and 

include requirements under CAA section 111(d) (40 CFR 70.2 and 

71.2 (definition of “applicable requirement”)).

The EPA anticipates that, given the nature of the units 

covered by the proposed federal plan, most of the sources at 

which they are located are already or will be subject to title V 

permitting requirements. For sources subject to title V, the 

 

38 Part 70 addresses requirements for title V programs implemented 

by state, local, and tribal governments, and part 71 governs the 

title V program implemented by the EPA or delegate agencies in 

areas under federal jurisdiction, such as Indian country.
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requirements applicable to them under the proposed federal plan 

will be “applicable requirements” under title V and, therefore,

will need to be addressed in the title V permits. For example, 

requirements under the proposed federal plan concerning 

designated representatives, monitoring, reporting, and 

recordkeeping, the requirement to either meet an emission rate 

(including through holding ERCs (rate-based approach)), or to 

hold allowances covering emissions (mass-based approach) will be 

“applicable requirements” to be addressed in the permits.

The EPA does not believe this approach is affected by the 

Supreme Court’s decision in Utility Air Regulatory Group v U.S. 

EPA, 134 S. Ct. 2427 (June 23, 2014). The Supreme Court held 

that the EPA may not treat GHGs as an air pollutant for purposes 

of determining whether a source is a major source required to 

obtain a title V operating permit. In accordance with that 

decision, the D.C. Circuit’s amended judgment on April 10, 2015 

vacated the title V regulations under review in that case (40 

CFR 70.12 and 71.13) to the extent that they require a 

stationary source to obtain a title V permit solely because the 

source emits or has the potential to emit GHGs above the 

applicable major source thresholds. The D.C. Circuit also 

directed the EPA to consider whether any further revisions to 

its regulations are appropriate in light of UARG v. EPA, and, if 
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so, to undertake to make such revisions. As the agency made 

clear in a memorandum to Regional Administrators last year, 

“While the EPA will no longer apply or enforce the requirement 

that a source obtain a title V permit solely because it emits or 

has the potential to emit greenhouse gasesGHGs above major 

source thresholds, the agency does not read the Supreme Court 

decision to affect other grounds on which a title V permit may 

be required or the applicable requirements that must be 

addressed in title V permits.”39 Accordingly, while the emission 

of GHGs alone cannot trigger the need for a title V permit under 

UARG, the EPA believes a final federal plan under CAA section 

111(d) will create new “applicable requirements” in the form of 

an emission standard (either an emission rate or an allowance 

system) and related requirements for GHGs (here, carbon 

dioxideCO2) on affected EGUs. See 40 CFR 70.2, 71.2 (definition 

of “applicable requirement” includes “any standard or other 

requirement under section 111 of the Act, including section 

111(d)”) (emphasis added). Thus, an affected EGU may be required 

to modify its existing title V permit, or obtain a new permit if 

 

39 Memorandum from Janet McCabe, Acting Assistant Administrator, 

Office of Air and Radiation, and Cynthia Giles, Assistant 

Administrator, to Regional Administrators, Regions 1-10, at 5 

(July 24, 2014).
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it does not already have one, if it becomes subject to an 

emission standard for carbon dioxide under aCO2under a CAA

section 111(d) federal plan.

The title V permits program is structured to provide 

flexibility for market-based approaches, such as allowance 

trading programs under the federal plan, including flexibility 

to make changes under such programs without necessarily 

requiring a formal permit revision. For example, the title V 

regulations provide that a permit issued under title V shall 

include, for any “approved * * * emissions trading or other 

similar programs or processes” applicable to the source, a 

provision stating that no permit revision is required “for 

changes that are provided for in the permit.” 40 CFR 70.6(a)(8) 

and 71.6(a)(8). Consistent with this provision in the title V 

regulations, the proposed federal plan regulations include a 

provision stating that no permit revision shall be required for 

the allocation, holding, deduction, or transfer of allowances

once the requirements applicable to such allocations, holdings, 

deductions, or transfers of CO2 allowances are already 

incorporated in such permit. Consistent with title V 

regulations, this provision should be included in each title V 

permit for a covered source. As a result, allowances will be 

able to be traded (or allocated, held, or deducted) under the 
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federal plan without a revision of the title V permit of any of 

the sources involved.

As a further example of flexibility under title V, the 

title V regulations allow the use of the minor permit 

modification procedures for permit modifications “involving the 

use of economic incentives, marketable permits, emissions 

trading, and other similar approaches, to the extent that such 

minor permit modification procedures are explicitly provided for 

in an applicable implementation plan or in applicable 

requirements promulgated by EPA.” 40 CFR 70.7(e)(2)(i)(B) and 40 

CFR 71.7(e)(1)(i)(B). Therefore, the EPA is proposing that any 

changes that may be required to an operating permit with respect 

to a trading program under the federal plan may be made using 

the minor permit modification procedures of the title V rules. 

The EPA proposes that such changes may include the initial 

changes needed to the title V permit to establish the 

applicability of the trading program to the source, specify the 

covered units, and to include other permit terms that may be 

needed for implementation, including the general approach for 

monitoring and reporting. The minor permit modification 

procedures could also be used for any subsequent changes to 

permit terms that may be needed with respect to the trading 

program, although we expect such changes to be infrequent. As 
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noted above, once a trading program has been established in the 

permit, there may be transactions, such as individual trades, 

that will require no formal permit modification procedures 

because such trading would be already addressed and allowed by 

the permit (“provided for in the permit”) and provided the 

changes do not conflict with any existing terms of the permit. 

If a sources wishes to make a change that would go against any 

express term of the permit, the permit must be revised to allow 

such a change before the source begins operation of the change. 

Under the implementation strategy described above, the EPA 

believes it would be unlikely that any change in trading 

allowances would violate a term of a permit, but this principle 

is important to keep in mind when deciding if a minor permit 

modification is appropriate with respect to operating a trading 

program in the context of a title V permit.

The EPA believes that the approach to permitting 

requirements we are proposing here, which imposes no additional 

permitting requirements independent of title V and provides for 

the use of minor permit modification procedures, will streamline 

the process for sources already required to be permitted under 

title V and for permitting authorities. If there are any sources 

that would become newly subject to title V as a result of the 

requirements of this proposed federal plan, the initial title V 
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permit that would be issued pursuant to 40 CFR 70.7(a) or 

71.7(a) would address the federal plan requirements, when 

finalized.

The EPA notes that the approach to title V permitting that 

is being proposed is somewhat similar to the approach adopted in 

the final Cross-State Air Pollution Rule (CSAPR).. See 76 FR 

48299-30 (Aug. 8, 2011). The agency recently issued guidance to 

assist permitting authorities and sources subject to CSAPR in 

incorporating CSAPR requirements into title V permits.40 The EPA 

invites comment on its proposed approach to permitting 

requirements for the federal plan, including whether it would be 

of use to develop guidance similar to the guidance developed for 

permitting under CSAPR. The EPA invites comment on its proposed 

approach to incorporating applicable requirements of the federal 

plan into title V permits and revising those requirements, 

including specifically seeking comment on whether all 

requirements should be eligible for incorporation into title V 

permits via minor modification procedures or if only a specified 

 

40 Memorandum from Anna Marie Wood, Director, Air Quality Policy 

Division, Office of Air Quality Planning and Standards (OAQPS), 

and Reid P. Harvey, Director, Clean Air Markets Division, Office 

of Atmospheric Programs (OAP), to Regional Air Division Directors, 

1-7, regarding Title V Permit Guidance and Template for the CrossState Air Pollution Rule (May 13, 2015).
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subset of such requirements should be eligible for such 

procedures.

The EPA also notes that the applicable requirements of this 

proposed federal plan would apply to a source and are 

independently enforceable regardless of whether they have yet 

been included in the source’s Title V permit.

2. Implications for New Source Review Program

The new source review (NSR) program is a preconstruction 

permitting program that requires major stationary sources of air 

pollution to obtain permits prior to beginning construction. The 

requirements of the NSR program apply both to new construction 

and to modifications of existing major sources. Generally, a 

source triggers these permitting requirements as a result of a 

modification when it undertakes a physical or operational change 

that results in a significant emission increase and a net 

emissions increase. NSR regulations define what constitutes a 

significant net emissions increase, and the concept is 

pollutant-specific. 

In the final EGs, &&&[citation], the EPA recognized that, 

as part of its CAA section 111(d) plan, a state may impose 

requirements that require an affected EGU to undertake a 

physical or operational change to improve the unit’s efficiency 

that results in an increase in the unit’s dispatch and an 
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increase in the unit’s annual emissions. If the emissions 

increase associated with the unit’s changes exceeds the 

thresholds in the NSR regulations for one or more regulated NSR 

pollutants, including the netting analysis, the changes would 

trigger NSR. We noted that while there may be instances in which 

an NSR permit would be required, we expect those situations to 

be few.

The EPA believes the analysis of NSR applicability is 

basically the same for sources under a CAA section 111(d) 

federal plan. That is, it is conceivable that a source under a 

federal plan may choose, as a means of compliance with either a 

rate-based or mass-based approach, to undertake a physical or 

operational change to improve an affected EGU’s efficiency that 

results in a significant net emissions increase of a regulated 

NSR pollutant. This would trigger NSR. However, as with state 

plans, the EPA believes that these situations will be few.

After the proposal for the Clean Power Plan was published 

in June of 2014, the United StatesU.S. Supreme Court issued its 

opinion in UARG v EPA, 134 S. Ct. 2427 (June 23, 2014). The 

Supreme Court held that an increase in greenhouse gasGHG

emissions alone cannot by law trigger the NSR requirements of 

the PSD program under section 165 of the CAA. On remand from the 

Court, the D.C. Circuit issued an amended judgment in Coalition 
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for Responsible Regulation, Inc. v. Environmental Protection 

Agency, Nos. 09-1322, 10-073, 10-1092 and 10-1167 (D.C. Cir., 

April 10, 2015), vacating the relevant regulations. Therefore, 

increases in emissions of greenhouse gasesGHGs alone, including 

those that may occur through actions taken at sources to comply 

with the proposed federal plan (such as may occur when an NGCC 

unit increases its operations due to generation shift from a 

steam generating unitSGU), cannot trigger NSR.

The EPA invites comment on what actions sources might take to 

comply with the federal plan that could trigger NSR, and what 

flexibilities may be available in the existing NSR program to 

avoid the need for pre-construction review in those 

circumstances.The EPA will invite comment on potential scenarios 

in which affected EGUs, particularly small entities, could be 

subject to the requirements of the NSR program as a result of 

taking compliance measures under the federal plan, and any ideas 

for harmonizing or streamlining the permitting process for such 

sources that are consistent with judicial precedent. However,

the EPA is not proposing any changes to the NSR program in this 

action, and the agency is not reopening or reconsidering any 

prior actions or determinations related to NSR in this action. 

Any comments related solely to the NSR program will be 

considered out ofoutside the scope of this proposed rule.3. 

Interactions with Other EPA Rules

Existing fossil fuel-fired EGUs, such as those covered in 

this proposal, are or will be potentially impacted by several 

other rules recently finalized or proposed by the EPA.41. These 

 

41 We discuss other rulemakings solely for background purposes. The 

effort to coordinate rulemakings is not a defense to a violation 

of the CAA. Sources cannot defer compliance with existing 
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rules include the Mercury and Air Toxics Standards (MATS) (77 FR 

9304; Feb. 16, 2012));42; the Cross-State Air Pollution Rule 

(CSAPR);; Requirements for Cooling Water Intake Structures at 

Power Plants (79 FR 48300; Aug. 15, 2014); Disposal of Coal 

Combustion Residuals from Electric Utilities (CCR Rule),, issued

on December 19, 2014; and the proposed Steam Electric Effluent 

Limitation Guidelines and Standards (SE ELG Rule) (78 FR 34432; 

June 7, 2013). These rules are discussed in more detail in the 

final EGs along with steps the EPA is taking to enable 

compliance with obligations under other power sector rules as 

efficiently as possible. &&&citation. We solicit comment on 

whether there are specific things the EPA can do in the design 

and implementation of the federal plan that further this 

objective.

I. Administrative Appeals Process

Under either a rate-based or mass-based trading program, 

the EPA anticipates that there may be situations in which 

individual parties are affected by decisions of the agency. For 

example, under a rate-based plan, a determination may be made 

 

requirements because of other upcoming regulations.

42 The Supreme Court recently reversed and remanded a D.C. Circuit 

Court of Appeals decision that had upheld the MATS rule. Mich. v. 

EPA, No. 14-46 (S. Ct. filed June 29, 2015). The Court did not 

vacate the rule, however, and it remains in effect.
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that an eligibility application by an ERC provider is denied. 

And, for set-asides in the mass-based program, an affected EGU 

may believe that its allowance allocation amount was 

miscalculated. Similar to prior trading programs, the agency 

believes it would be efficient and potentially avoid the need 

for recourse to litigation, to provide an administrative appeals 

process. Therefore we are proposing, and requesting comment on, 

the use of the regulations for appeals procedures set forth in 

40 CFR part 78, to provide for the adjudication of certain 

disputes that may arise during the course of implementation of a 

federal plan under CAA section 111(d). We also propose to revise 

part 78 to accommodate such appeals. The part 78 procedures 

cover prior CAA emission trading programs and were specifically 

designed with these types of disputes in mind.

The persons eligible to file such appeals would be similar 

to the existing definition of an “interested person” in part 78. 

The filing of an appeal and the exhaustion of administrative 

remedies under part 78 would be a prerequisite to seeking 

judicial review. For purposes of judicial review, final agency 

action would occur only when an agency decision under the 

federal plan listed as appealable under part 78 has been issued, 

and the procedures of part 78 for appealing the decision are 

exhausted. 
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The actions we propose to list as appealable under the part 

78 procedures are as follows. 

In the case of the rate-based federal plan: decisions on an 

eligibility application for ERCs; decisions regarding the number 

of ERCs generated; decisions on the transfer of ERCs; decisions 

on the disallowance of ERCs for compliance; decisions that there 

has been an excess of emissions requiring a 2-for-1 ERC 

administrative compliance penalty; decisions regarding deduction 

or surrender of ERCs for compliance from affecteaffected EGUs’ 

compliance accounts; decisions on the accreditation of 

independent verifiers; the use of error corrections regarding 

information submitted by ERC providers, affected EGUs, or other 

ERC account holders; and the finalization of controlcompliance 

period emissions data, including retroactive adjustment based on 

audit or other investigation. 

In the case of a mass-based federal plan: decisions on an 

eligibilty application for set-aside allowances; decisions 

regarding the allocation of allowances to affected EGUs; 

decisions regarding the allocation of allowances from setasides; decisions on the transfer of allowances; decisions 

regarding the finalization of emissions data by affected EGUs 

during compliance periods; decisions making error corrections to 

information submitted by affected EGUs and other account 
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holders; decisions that there has been excess emissions 

requiring a 2-for-1 allowance administrative compliance penalty; 

and decisions regarding the deduction or surrender of allowances 

for compliance from affected EGUs’ compliance accounts. 

We request comment on this list of actions for both types 

of approaches to the federal plan, and whether there are other 

decisions that may be made in the course of implementation of 

the federal plan that are party-specific that would be 

appropriate to list as appealable under part 78. We also take 

comment on whether it would be appropriate for the EPA to 

finalize an administrative appeals process that differs in any 

way from that offered under part 78, or in addition to that 

offered under part 78. If so, we request comment broadly on all 

aspects of the alternative or additional adminsitrative appeals 

process, including with respect to any structural, procedural, 

subtantive, and timing requirements it should include, who 

should have access to it and in what manner, and how it would 

differ from part 78. Finally, we request comment on whether, 

similar to other programs identified in 40 CFR 78.1(a)(1), the 

agency should make the procedures of part 78 available to any 

actions of the Administrator under the comparable state 

regulations approved as a part of a state plan under the EGs.
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J. Consistency of Program Structure with Clean Air Act Authority 

The EPA is co-proposing two distinct forms of emissions 

trading as the mechanism for federal implementation of standards 

of performance that achieve the emission performance levels by

determined by application of the Best System of Emission 

Reduction (BSER) in the Clean Power Plan EGs. Both proposals are 

“emission standard” approaches as defined in the EGs, and the 

EPA is not proposing an approach like the “state measures” 

approach that is also available to states in the final EGs. The 

EPA has legal authority to establish either of the proposed 

trading systems as a federal plan under CAA section 111(d)(2). 

We discuss this topic briefly here and invite public comment.

The EGs discussed the role of emissions trading in the BSER, 

see, e.g., section V.A of the preamble to the final EGs. The EPA 

regards this to be a separate issue and is not revisiting or 

reopening the discussion of the BSER or the role of trading in 

the BSER here. The EGs recognize and provide ample opportunity 

for states to establish standards of performance that allow the 

use of emissions trading or other multi-unit compliance 

approaches. Here we discuss why an emissions trading program is 

a lawful and appropriate form of federal “implementation” of a 

"“standard of performance"” under CAA section 111(d)(2). We 

invite comment on this legal discussion and the agency’s 
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interpretation of its authority.

1. General Section 111(d)(2) Authority

Section 111(d)(2) provides as follows: 

The Administrator shall have the same authority—

(A) to prescribe a plan for a State in cases where the 

State fails to submit a satisfactory plan as he would have 

under section 7410(c) of this title [CAA section 110(c)] in 

the case of failure to submit an implementation plan, and 

(B) to enforce the provisions of such plan in cases 

where the State fails to enforce them as he would have 

under sections 7413 and 7414 of this title [CAA sections 

113 and 114] with respect to an implementation plan. 

In promulgating a standard of performance under a plan 

prescribed under this paragraph, the Administrator shall 

take into consideration, among other factors, the remaining 

useful lives of the sources in the category of sources to 

which such standard applies.

42 U.S.C. 7411(d)(2).43

The phrase “same authority to prescribe” indicates that 

Congress viewed the EPA’s authority to issue a federal plan for 

designated pollutants under CAA section 111(d) as, in some 

 

43 The agency’s interpretation of the “remaining useful lives” 

provision is discussed above in section III.G of this preamble.
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sense, co-extensive with its authority to issue a FIP for 

National Ambient Air Quality Standards (NAAQS) pollutants under 

CAA section 110. This authority under CAA section 111, of 

course, must be understood in reference to the purpose of that 

section (i.e., to achieve emission reductions for designated 

pollutants from designated facilities), rather than in reference 

to the purpose of section 110 (i.e., to attain and maintain the 

NAAQS). However, it has been the agency’s longstanding view 

that, in both procedural and substantive respects, Congress 

intended that the CAA section 110 authority be looked to under 

CAA section 111(d)(2). See 40 FR 53340, at 53342 (Nov. 17, 1975) 

(“It is obvious that [the Administrator] could only prescribe 

standards on some substantive basis. The references to section 

110 of the CAA suggest that (as in CAA section 110) [she] was 

intended to do generally what the states in such cases should 

have done, which in turn suggests that (as in CAA section 110) 

Congress intended the states to prescribe standards on some 

substantive basis. Thus, it seems clear that some substantive 

criterion was intended to govern not only the Administrator’s 

promulgation of standards but also [her] review of state 

plans.”). 

Over the several decades of implementation of the Clean Air 

ActCAA, the courts, and the EPA, have addressed the nature and 
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scope of CAA section 110 authority. See, e.g., 71 FR 25328, 

25338 (May 12, 2005) (CAIR final rule). In general, the EPA has 

broad power under CAA section 110(c) to cure a defective state 

implementation plan.SIP. Thus, in promulgating a FIP under CAA 

section 110, the EPA may exercise its own, independent 

regulatory authority in accordance with CAA section 110(c) and 

the CAA more broadly. When the EPA has promulgated a FIP, courts 

have not required explicit authority for specific measures: “We 

are inclined to construe Congress'Congress’ broad grant of power 

to the EPA as including all enforcement devices reasonably 

necessary to the achievement and maintenance of the goals 

established by the legislation.” South Terminal Corp. v. EPA, 

504 F.2d 646, 669 (1st Cir. 1974). Further, the same authority 

that is exercised by the states under the CAA in connection with 

the adoption, implementation, and enforcement of a SIP may be 

assumed to be available to the EPA when the agency issues a FIP, 

after determining that a state has not adopted a satisfactory 

SIP. As the Ninth Circuit has held, when the EPA acts in place 

of the state pursuant to a FIP under CAA section 110(c), the EPA 

“stands in the shoes of the defaulting state, and all of the 

rights and duties that would otherwise fall to the state accrue 

instead to EPA.” Central Ariz. Water Conservation Dist. V. EPA, 

990 F.2d 1531, 1541 (9th Cir. 1993). Accord, South Terminal, 504 
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F.2d at 668 (“[T]he Administrator must promulgate promptly 

regulations setting forth an implementation plan for a state 

should the state itself fail to propose a satisfactory one. The 

statutory scheme would be unworkable were it read as giving to 

the EPA when promulgating an implementation plan for a state, 

less than those necessary measures allowed by Congress to a 

state to accomplish federal clean air goals. We do not adopt any 

such crippling interpretation.”).

By the same token, if there are clear limits to the EPA’s 

CAA section 110(c) authority, those too, would arguably carry 

over to CAA section 111(d)(2). For instance, CAA section 

110(c)(1) ties the EPA’s authority to promulgate a final FIP for 

a state to the EPA’s predicate action on a state implementation 

plan SIP(or lack thereof): generally, either an action 

disapproving a plan, or a finding that a state has failed to 

submit a plan. However, even here, as the Supreme Court has 

recognized, “the plain text of the CAA grants EPA plenary 

authority to issue a FIP ‘at any time’ within the two2-year 

period that begins the moment EPA determines a SIP to be 

inadequate.” EPA v. EME Homer City Generation, 134 S. Ct. 1584, 

1602 n.14 (2014). 

Congress gave the EPA the same authority to prescribe a 

plan under CAA section 111(d)(2) as it possesses under CAA 
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section 110(c). The EPA believes this authority is the “same” in 

the sense described above and in the case law.44 The scope of the 

EPA’s action to undertake a FIP under CAA section 110 is 

informed by the scope of the state’s action to undertake a SIP; 

likewise, the scope of the EPA’s action to undertake a federal 

plan under CAA section 111(d) is informed by the scope of the 

state’s action to undertake a state plan.

The agency received comments on the proposed EGs from 

commenters who stated that the EPA cannot require states to 

implement the building blocks that make up the BSER,; for example,

ordering re-dispatch to natural gas-fired units, or ordering the 

construction of renewable energyRE projects. These commenters went 

on to say that the EPA itself would have no authority to order 

these types of actions under a federal plan. As we explained in 

the Legal Memorandum for the final EGs, and reiterate here, the 

 

44 We interpret the cross-reference to be to the currently enacted 

version of CAA section 110(c), rather than to a prior version. As 

discussed in section VII of this preamble, below, the current 

version of CAA section 110, including subsection (c), reflects 

changes made in the 1990 Amendments based on experience gained in 

the first two decades of the CAA’s implementation. The statute and 

legislative history do not expressly address the question, but 

there is no indication Congress would have intended to prevent 

these improvements from being available under CAA section 111 as 

well.
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premise of these comments is incorrect. The EPA is not requiring 

the implementation of the BSER or the building blocks in the EGs.

Even where the EPA is directly implementing standards of 

performance in a federal plan, the agency will not, and need not, 

attempt to order sources to implement the measures that comprise 

the BSER. Rather, as set forth in the co-proposed federal plans

discussed in sections IV and V of this preamble, the EPA would set 

emission standards for each of the affected EGUs in the federalplan state, provide mechanisms for their implementation and 

enforcement, and otherwise leave to the owners and operators of 

the affected EGUs the decisions about what measures they want to 

take to comply with the emission standard. Though the emission 

standards will be federally enforceable, as under a state plan, 

sources may achieve them through implementation of measures in the 

BSER, or any other method.

Thus, the question whether the EPA would have the authority 

to directly order the implementation of the measures in the 

building blocks in this proposed federal plan is not only not 

relevant but represents a categorical misunderstanding of the 

nature of the BSER in relation to the imposition of standards of 

performance under a CAA section 111(d) plan. To illustrate this, 

by the same token the EPA could not enforce many logistical aspects 

of a control requirement such as a scrubber – for instance, the 
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EPA does not need to assert the authority to order into existence

companies that manufacture scrubbers, or order their construction 

or delivery on a certain schedule. The EPA need not in setting 

emission standards have before it all of the information regarding

manufacturing, transportation of parts, or other logistical 

requirements to ensure that each scrubber gets constructed and 

delivered to a source. Similarly, the EPA here does not, and needs 

not, propose an implementation approach of directly intervening to 

re-dispatch certain units, construct new renewable energyRE

projects, or take other measures, either included in the BSER or 

not. The agency determined the BSER and emission performance levels 

in the EGs on a reasonable assumption that all of those things can 

actually happen. In providing for the implementation of federally 

enforceable standards of performance in the federal plan proposed

in this action, the agency is ensuring that these things will 

happen.

2. Use of Market Techniques to Implement Standards of Performance 

under the Clean Air Act

The use of market techniques such as emission trading is 

well-supported in the Clean Air ActCAA and has many regulatory 

precedents. The EPA discussed this history, and the reason why 

trading is a supportable method of implementation of standards 

of performance under CAA section 111(d) in the Emissions 
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GuidelinesEGs. See section V.A of the final EGs. Here we

supplement that discussion with respect to the agency’s own 

authority under CAA section 111(d)(2) to use trading as a method 

of implementation of a “standard of performance” in the federal 

plan.

The 1990 CAA Amendments added broad authorizations for the 

use of market techniques in several sections of the statute, 

including in Title I. States were provided express authority to 

use such approaches in their NAAQS implementation plans under 

CAA section 110(a)(2)(A): “Each [state] plan shall—include 

enforceable emission limitations and other control measures, 

means, or techniques (including economic incentives such as 

fees, marketable permits, and auctions of emissions rights)....” 

42 USC 7410(a)(2)(A). The EPA was given similar authority in the 

definition of a “Federal Implementation Plan” in CAA section 

302: “The term ‘Federal implementation plan’ means a plan (or 

portion thereof) promulgated by the Administrator ... which 

includes enforceable emissions limitations or other control 

techniques (including economic incentives, such as marketable 

permits or auctions of emissions allowances), and provides for 

attainment of the relevant national ambient air quality 

standard.” 42 U.S.C. 7603(y). Section 111(d)(2) of the CAA

provides the EPA “the same power to prescribe” a federal plan 
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under CAA section 111 as it would have to promulgate a FIP under

CAA section 110(c). Thus, the EPA believes the plain language of 

the statute authorizes the use of market techniques in CAA 

section 111(d) federal plans.

However, even if one were to view this language as not 

wholly unambiguous with respect to the scope of federal 

authority under CAA section 111, the EPA believes that CAA

section 111, in conjunction with authorizations and endorsements 

of market techniques throughout the ActCAA, and other indicia of 

congressional intent, strongly support the view that market 

techniques are within the EPA’s authority to promulgate a 

federal plan under CAA section 111(d).

Case law throughout the history of the CAA has generally 

confirmed the legal viability of emissions trading as an 

implementation measure so long as the trading ultimately 

achieves the emission reduction goals of the statute. See, e.g., 

Sierra Club v. EPA, No. 12-3169 (6th Cir. Filed March 18, 2015), 

Slip Op. at 11-14 (upholding EPA approval of redesignation of 

area to attainment on basis that reductions in emissions from 

cap-and-trade programs (NOx SIP Call, CAIR, and CSAPR) are 

permanent and enforceable). Chevron, U.S.A., Inc. v. Natural 

Res. Def. Council, Inc., 467 U.S. 837 (1984) (“Chevron”), the 

seminal case establishing the Supreme Court’s standard of review 
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of agency interpretations of the statutes they administer, 

upheld one of the EPA’s early emissions trading programs, the 

Netting Rules of 1980 (45 FR 52676; Aug. 7, 1980), which the EPA 

in its discretion chose to allow states to apply in both 

attainment and nonattainment areas (46 FR 50766; Oct. 14, 1981). 

The Netting Rules allowed existing major sources to modify 

without triggering certain requirements of PSD or nonattainment 

NSR, so long as any increase in emissions associated with the 

modification is compensated for by a corresponding decrease in 

emissions elsewhere within the same facility, such that there is 

no significant net increase in emissions from the facility as a 

whole. In upholding this approach in Chevron, the Supreme Court 

gave deference to the EPA’s definition of the term “source,” 

finding in that term sufficient ambiguity to support the 

agency’s reasoned application of an emissions averaging approach 

for total pollution emitted from the source. See EPA v. EME 

Homer City, 134 S. Ct. 1584, 1603 (2014) (“Because ‘a full 

understanding of the force of the statutory policy . . . 

depend[s] upon more than ordinary knowledge’ of the situation, 

the administering agency’s construction is to be accorded 

‘controlling weight unless . . . arbitrary, capricious, or 

manifestly contrary to the statute.’”) (quoting Chevron, 467 
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U.S. at 844).45

With the increasing recognition of the utility of trading, 

crediting, and averaging to meet emission reduction goals

efficiently, the EPA set forth a comprehensive policy on trading 

in 1986. Emissions Trading Policy Statement; General Principles 

for Creation, Banking and Use of Emission Reduction Credits, 51 

FR 43814 (Dec. 4, 1986) (hereinafter “ERC Policy”). In the ERC 

Policy, the EPA stated that it “endorses emissions trading and 

encourages its sound use by states and industry to help meet the 

goals of the Clean Air ActCAAt more quickly and inexpensively.” 

At the same time, based on lessons learned from its earlier 1982 

trading policy, the EPA took steps to tighten its policies on 

the use of “bubbles” to ensure environmental integrity of 

trading, particularly in non-attainment areas. The agency 

emphasized the requirements of enforceability, tracking (and 

 

45 The EPA is not aware of any case since at least the Chevron

decision in which a trading program under the CAA was invalidated 

simply by virtue of being a trading program. The CAIR trading 

program was set aside by the D.C. Circuit because the court held 

it did not accomplish the objective of the Good Neighbor provision 

of the CAA, not because it used a trading approach per se. North 

Carolina v. U.S. EPA, 531 F.3d 896, 921 (D.C. Cir. 2008). More 

recently the Supreme Court upheld key portions of the CSAPR trading 

program that replaced CAIR in EPA v. EME Homer City, 134 S. Ct. 

1584 (2014).
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preventing double-counting), determining the appropriate 

baseline from which to measure emissions, and demonstration of 

actual air quality benefits.

The use of an emissions trading system for CO2 reductions 

for affected EGUs under CAA section 111(d) is also analogous to 

the trading system for chlorofluorocarbons (CFCs) under the pre1990 CAA provision for control of stratospheric ozone depleting 

substances. This program was reviewed by the Office of Legal 

Counsel (OLC) within the Department of Justice in 1989. See

Memorandum for Alan Raul, General Counsel, Office of Management 

and Budget, from the Office of the Assistant Attorney General 

(April 14, 1989) (hereinafter “OLC Memo”).46 The OLC was asked by 

OMB to opine whether a general grant of regulatory authority to 

the EPA to “control” CFCs was sufficient to authorize an 

emissions fee or a cap-and-trade system, including auction, of 

tradable allowances. The statute authorized the EPA to issue 

regulations “for the control of any substance, practice, 

process, or activity (or any combination thereof) which in his 

judgment may reasonably be anticipated to affect the 

stratosphere, especially ozone in the stratosphere, if such 

effect in the stratosphere may reasonably be anticipated to 

 

46 A copy of this memorandum has been placed in the docket for this 

rulemaking.
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endanger public health.” Former CAA 157(b) (as enacted in the 

1977 CAA amendments). The Office of Legal Counsel concluded that 

this language --– which it characterized as “plain,” 

“unambiguous,” and “sweeping” --– was sufficient to authorize 

the EPA to establish a cap-and-trade program with auction for 

CFCs. See id. At 7 (“It cannot seriously be argued that the use 

of economic incentives to regulate pollution is a novel or 

strange idea that could not have been anticipated by the authors 

of the Clean Air Act Amendments [of 1977].”) (citing multiple 

examples from the policy literature as early as E. Mishan, The 

Costs of Economic Growth (1967).)). The OLC noted that as of 

1977, “Congress was cognizant of economic forms of regulation, 

did not prohibit them, but instead used general language 

permitting a wide scope of regulatory measures for the control 

of CFCs.” To interpret the general authority of this section of 

the CAA as affirmatively prohibiting market incentives would be, 

in the OLC’s words, to read into the statute the italicized 

clause “regulations for the control [of CFCs] by traditional 

command and control or specification standard methods,” id. At 9 

– a rewriting “unwarranted in any case, but especially so where 

Congress was aware of economic methods of control and where such 

methods so ably serve the underlying purposes of the statute.” 

Id.
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By the time of the 1990 CAA Amendments, as discussed above, 

Congress was comfortable enough with the efficacy of market 

techniques that they were broadly authorized for use in 

stateSIPs and FIPs for NAAQS. See 42 U.S.C. 7410(a)(2)(A), 

7602(y). In the wake of the 1990 Amendments, the EPA issued an 

“Implementation Strategy for the Clean Air Act Amendments of 

1990.”47 This Strategy included as one of nine overarching 

implementation principles, “Market-based: Use of market-based 

approaches and other innovative strategies to creatively solve 

environmental problems.” Further, it announced that the EPA 

would make “full use of innovative market-based approaches,” and 

that the agency will supplement traditional approaches with 

broader use of market incentives and other innovative approaches 

“whenever possible.” Id. At 3, 9.

Since the 1990 Amendments, the EPA has established three of 

its most robust trading programs – the Federal NOx Budget Trading 

Program (65 FR 2674; Jan. 18, 2000), the Clean Air Interstate 

Rule (CAIR) (71 FR 25328; April 28, 2006), and the Cross-State

Air Pollution Rule (CSAPR) (76 FR 48208; Aug. 8, 2011), under

 

47 U.S. EPA, Office of Air and Radiation, Implementation Strategy 

for the Clean Air Act Amendments of 1990 (Update, 1992) (July 

1992), 400-K-92-004.
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CAA section 110(a)(2)(D)(i)(I), relating to air pollution that 

causes nonattainment or interference with maintenance of air 

quality standards in downwind states.48

As noted in the rulemaking notice for the final EGs,

&&&cite&&&, the EPA has instituted or authorized the use of 

emissions trading programs twice in the past under CAA section 

111(d). The EPA authorized NOx emissions averaging or trading 

within or between facilities under the Municipal Waste 

Combustors Emission GuidelinesEGs in 1995. 60 FR 65387, 65402 

(Dec. 19, 1995) (codified at 40 CFR 60.33b(d)(1) and (2)). The 

EPA also developed a cap-and-trade system for mercury under CAA 

section 111(d) in the Clean Air Mercury Rule (CAMR). 70 FR 28606 

(May 18, 2005). The EPA proposed a federal plan for trading that 

was identical in all relevant respects to the CAMR rule. 71 FR 

77100 (Dec. 22, 2006). However, CAMR was vacated by the D.C. 

Circuit on grounds unrelated to the establishment of a trading 

system for implementation, before the CAMR federal plan could be 

 

48 The EPA notes that complications that arise with respect to 

assigning a “significant contribution” among upwind states for 

NAAQS pollutant levels in downwind states, and designing a trading 

regime that accomplishes Good Neighbor objectives, are not present 

with respect to CO2, which is a global pollutant; emission 

reductions anywhere contribute to the environmental objective of 

addressing climate change.
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finalized. New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008).49

The agency believes these legal and administrative 

precedents for federal trading programs under the Clean Air 

ActCAA going back decades amply support its decision to propose 

two forms of emission trading as the method of implementation of 

the Clean Power Plan EGs in the federal plan. Notably, emissions 

trading is particularly appropriate with respect to a global 

pollutant such as carbon dioxide thatCO2that is well-mixed in the 

atmosphere and does not have direct, acute health impacts due to 

inhalation at ambient levels.50

Finally, the Supreme Court has affirmed the breadth of the 

agency’s discretion under CAA section 111(d) to select the 

method by which it would control carbon dioxide 

emissionsCO2emissions from existing power plants. See AEP v. 

Connecticut, 131 S. Ct. 2527, 2538 (2011) (“Congress delegated 

 

49 The CAMR program was vacated because the EPA had not made 

requisite findings under CAA section 112(c)(9) in delisting EGUs 

with respect to emissions of a hazardous air pollutants (HAP). No 

such procedural concern is present here with respect to CO2, which 

is not a HAP under CAA section 112.

50 We recognize that some commenters on the EGs raised concerns 

about the localized impacts that may occur from the potential for 

concentrations of co-pollutants associated with CO2emitted from 

affected EGUs. We address those concerns in the communities 

sections of the final EGs, at section IX, and in this preamble in 

section IX below. 
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to EPA the decision whether and how to regulate carbon-dioxide 

emissions from power plants.”) (emphasis added); see also id. At 

2539 (“The appropriate amount of regulation in any particular 

greenhouse gasGHG-producing sector cannot be prescribed in a 

vacuum: as with other questions of national or international 

policy, informed assessment of competing interests is required. 

Along with the environmental benefit potentially achievable, our 

Nation’s energy needs and the possibility of economic disruption 

must weigh in the balance. The Clean Air ActCAA entrusts such 

complex balancing to the EPA in the first instance, in 

combination with state regulators.”). 

This proposal is guided by the relevant cases and the 

experiences of the agency in implementing the CAA trading 

programs discussed above. The EPA invites comment on this 

discussion and the agency’s interpretation that CAA section 

111(d)(2) authorizes the two approaches to a federal plan

proposed here.

IV. Rate-based Implementation Approach

A. Overview 

The EPA’s federal plan requirements for CO2 from affected 

EGUs implement the EGs as previously discussed. In this federal 

plan and model rule proposal the EPA is proposing, as one 
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option, rate-based emission standards (i.e., the emission 

standard approach) for affected EGUs not covered by an approved 

state plan as specified in the CPP EGs.Clean Power Plan. The EPA 

is proposing to apply the subcategorized emission rates in this 

federal plan proposal. These rate-based emission standards are 

consistent with, and would satisfy, the degree of emission 

limitation achieved by the BSER determination made in the final 

CPPClean Power Plan EGs, which included sub-categorized CO2

emission performance rates for affected EGUs to meet during the 

plan performance periods. An affected EGU subject to this 

federal plan will demonstrate compliance by achieving a stack 

emission rate less than or equal to the rate-based emission 

standard or by applying ERCs, acquired by the EGU, to its 

measured stack emissions rate. The application of ERCs by an 

affected EGU to comply with an emission standard has been

determined in the final CPP EGsClean Power Plan as a mechanism 

available to affected EGUs with a CO2 emission rate greater than 

its respective performance rate to meet compliance obligations, 

see section IV.A.5.a [&&&]VIII.K of the CPPfinal EGs. Under a 

rate-based federal plan, the EPA would act as the state 

described in section VIII.C.31.a of the CPP [&&&]final EGs with 

the EPA acting as the issuer of ERCs, and otherwise implementing 

and enforcing the standards of performance for affected EGUs 
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subject to the federal plan.

This section describes the proposed rate-based federal plan 

and model trading rule and how each would be designed and 

operated, consistent with the emission guidelines.EGs. For the 

federal plan, the EPA is proposing to limit the issuance of ERCs 

to designated categories of affected EGUs and to renewable 

energyRE resources and certain nuclear generation (from new 

capacity and incremental capacity uprates) that are measured by 

a revenue quality meter, rather than the full suite of options 

discussed in the emission guidelines.EGs. The EPA requests 

comment on whether to limit the scope of the federal plan in 

this manner, and if not, what other sources of low- or zeroemitting electricity in federal plan states should also be 

eligible to generate ERCs for compliance purposes. For both the 

proposed federal plan and model rule, the EPA requests comment 

on which EM&V plan, M&Vmeasurement and verification (M&V)

report, and verification report requirements should apply for 

each eligible resource. Further discussion of non-BSER measures 

that may be eligible to generate ERCs can be found in the CPP 

EGsClean Power Plan and section IV.C.23 of this preamble. (The 

EPA is not reopening its determination of the BSER.)

B. Rate Goals

In the CPP EGsClean Power Plan the EPA identified a rate-
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based “emission standards” approach as an approvable method for 

state plans to implement the final EGs. In this approach the 

requirements for compliance rest solely on affected EGUs in the 

form of federally enforceable emission standards expressed as a 

rate of emissions of CO2 per unit of energy output. In the CPP 

EGsClean Power Plan, the EPA established, through application of 

the BSER, separate CO2 emission performance rates for affected 

EGUs in two subcategories. The two subcategories are natural 

gas-fired stationary combustion turbines (i.e., natural gas 

combined cycle units, or NGCC units) and fossil fuel fired steam 

generating unitsSGUs (i.e., utility boilers and IGCC units)51. 

The CO2 emission performance rates set in the CPP EGsClean Power 

Plan are reflected below in Table 46 of this preamble. The EPA 

is proposing to apply these rates in the rate-based federal plan

as the emission standards for NGCC units, and steam generating

unitsSGUs, respectively. For a thorough discussion of affected 

EGU category-specific CO2 emission performance rates and 

rationale, see section VI &&& of the CPPfinal EGs. These 

calculated standards and the premises that these standards are 

based on are not within the scope of comment in this rulemaking

as they were finalized in the CPP EGsClean Power Plan.

 

51 For simplicity, affected utility boilers and IGCC units will 

collectively be called “steam generating units.”
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As discussed in section III.D of this preamble above, the 

EPA proposes to implement a compliance schedule for the ratebased federal plan with multi-year compliance periods as 

follows: A three3-year period (2022 through 2024), followed by a 

three3-year period (2025 through 2027), followed by a two2-year 

period (2028 and 2029), for the interim period; and, commencing 

in 2030, successive two2-year compliance periods for the final 

period. In the CPP EGsClean Power Plan, the EPA established CO2

emission performance rates for the subcategories of affected 

EGUs for the performance periods. The EPA proposes to use those 

emission performance rates promulgated in the CPP EGsClean Power 

Plan as the emission rate standard for the respective EGUs that 

would become subject to this proposed federal plan if finalized. 

The EPA is not opening for comment the determinations made in 

the CPP EGsClean Power Plan of each subcategorized CO2 emission 

performance rates. The emission rate standards for respective 

EGU types are provided for convenience in Table 4.6 of this 

preamble.

The EPA is proposing to use a glide path during the interim 

period for EGUs to provide a smooth transition to the final 

compliance periods after 2030. This approach is 

describedestablished in section &&& ofthe final EGs. In Table 

6of this preamble. In Table 4. below, the applicable standards 
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for each interim compliance period is listed.

Table 46. Glide Path Interim Performance Rates (Adjusted OutputWeighted-Average Pounds of CO2 Per Net MWh From All Affected 

Fossil Fuel-Fired EGUs) 

Technology

2022-2024 

Compliance 

Rate

2025-2027 

Compliance 

Rate

2028-2029 

Compliance 

Rate

Final 

Rate

SGU or IGCC

1,671 1,500 1,380 1,305

Stationary 

combustion turbine

877 817 784 771

The EPA is using the subcategorized rates in the rate-based 

trading approach because it allows ERCs to be fungible across 

jurisdictional borders and provides an incentive structure, as 

compared to other rate-based approaches, that facilitates 

implementation of measures identified as part of the BSER. Using 

subcategorized rates allows for: (1) a relatively equitable 

distribution of burden for emission reductions aross the 

sectorconsistently applied emission rates for power plants of 

different types ; and (2) free trading of fungible ERCs among 

all affected EGUs subject to the federal plan and within the 

federal trading program. The EPA solicits comments on whether 

the subcategorized rate approach is the preferred rate-based 
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approach for the federal plan and model trading rule.52 If a 

subcategorized approach for a rate-based model rule and federal 

plan is not preferred by commenters, the EPA requests comment on 

the perceived benefits of an alternative rate or set of rates

(e.g., applying a uniform rate, i.e., the state goal, to all 

affected units within the state as the EGUs’ emission standard).

C. Crediting Mechanism

Under a rate-based emission standard approach in the 

federal plan, we are proposing that EGUs subject to the emission 

performance requirements for GHGs will either need to emit at or 

below their emission rate standard, or they will need to acquire 

ERCs to achieve compliance. An ERC is a tradable compliance unit 

representing one MWh of electric generation (or reduced 

electricity use) with zero associated CO2 emissions. These ERCs 

may then be used to adjust the measured and reported CO2 emission 

rate of an affected EGU when demonstrating compliance with a 

rate-based emission standard. For each ERC, one MWh is added to 

the denominator of the reported CO2 emission rate, resulting in a 

lower adjusted CO2 emission rate.

Under this proposed federal plan, ERCs will be issued by 

the EPA to three categories of entities: (1) Affected EGUs that 

 

52 Note that the values of limits and determinations made as the 

BSER are not open for comment.
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perform at a rate below the applicable emission rate standard;

(2) affected NGCC units for all generation (represents shifting 

generation from steam generating unitsSGUs to NGCC units, as 

anticipated under Building Block 2); and (3) new nuclear units 

and capacity uprates at existing nuclear units, and (4) RE 

providers that develop metered projects and programs whose 

results, in MWh, are quantified and verified according to EM&V 

criteria as described below in section &&& IV.D.68 of this 

preamble. We are also discussing in this preamble, taking 

comment on for the federal plan, and proposing for the model 

trading rule a potential fourth category: other low- and zeroemitting non-BSER measures that are described in section IV.C.23

of this preamble [&&&].. The concept of using an ERC as a

crediting mechanism to meet compliance obligations is consistent

with the CPP EGs and is being adopted in this federal plan.53.

Because the goal of this rulemaking is the actual reduction 

of CO2 emissions, it is fundamental that ERCs represent the MWh 

of energy generation or savings they purport to represent. To 

this end, only valid ERCs that actually meet the standards 

articulated in this rule may be used to satisfy any aspect of 

 

53 The use of ERCs and definition as a compliance mechanism to meet 

the BSER emission performance rates is established in section 

VIII.K of the final EGs. 
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compliance by an affected EGU with emission standards. The 

responsibility for the validity of the ERC rests with the 

affected EGU. Despite safeguards included in the structure of 

ERC issuance and tracking systems, such as the review of 

eligibility applications and M&V reports, and EPA issuance of 

ERCs, ERCs may be issued that do not, in fact, represent 

eligible zero-emission MWh as required in the EGs. A variety of 

situations may result in such improper ERC issuance, ranging 

from simple paperwork errors to outright fraud. The EPA requests 

comment on ways that the EPA could safeguard the validity of an 

ERC.

1. ERCs Generated and Owed Against a Standard

The number of ERCs generated or needed for surrender by an 

affected fossil fuel-fired EGU is based on the CO2 emission rate 

of the EGU in comparison to an emission rate standard. The 

calculation of ERCs generated by an EGU or needed for compliance 

is the CO2 stack emission rate of the EGU subtracted from the 

standard the EGU is subject to, and this value is subsequently 

divided by the standard the EGU is subject to. This value is a 

normalized quantity of how much better or worse the EGU is 

performing compared to its standard. The normalized value is 

weighted by multiplying the MWh electricity output from the EGU

at that emission rate. This can be generically expressed as:
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ERCs = (EGU standard − EGU operating rate)

EGU standard ∗ EGU generation

If the value calculated is positive, this indicates the number 

of ERCs that are being generated; conversely, a negative value 

indicates how many ERCs will need to be acquired to meet the 

unit’s emission rate for that compliance period. ERCs will be 

issued on an annual basis to ERC providers (i.e., entities 

generating ERCs via the ERC approval and issuance process 

detailed below). Surrender of ERCs for compliance by affected 

EGUs will not occur until the end of the compliance period as 

further described in section &&&IV.D.10 of this preamble.

As an example, assume a steam EGU operating in the second 

interim compliance period is subject to a rate standard of 1,500

lbs CO2/MWh. Assume it operates at 2,000 lbs CO2/MWh, and also 

assume it generates 1 million MWh over a compliance period. Its 

total emission rate would be 2 billion lbs CO2 / 1 million MWh. 

In order to achieve the emission standard, it would need to 

purchase 333,334 ERCs (rounded to the nearest higher integer). 

In essence, this quantity of ERCs represents the quantity of MWh 

that need to be added to the steam EGU’s denominator (i.e.,

generation, here, 1 million MWh), such that 2 billion pounds of 

CO2 (total emissions), divided by total generation (i.e., in this 

case, 1,333,334 MWh) equals the emission rate for compliance 
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(1,500 lbs/MWh). 

The discussion in this subsection builds on and applies the 

definition, benefits, use, and determination of using ERCs from 

the CPPfinal EGs (section VIII &&&.of the final EGs). We invite 

comment on use of the approach just described as a method of 

implementation of a federal plan and a model trading rule, and

we take comment on any alternatives to this approach that still 

fall within the established criteria described in the CPP EGs. 

Comments that solely relate to determinations finalized in the 

EGs will be considered out ofoutside the scope of this proposed 

rule.

2. Incremental NGCC ERCs

Building Block 2 (BB2) of the BSER determination in the CPP 

EGs describes shifting generation from steam generating 

unitsSGUs to NGCC units because NGCC units generate electricity 

at a less carbon intensive rate. BB2 describes NGCC units 

generating at 75 percent of the unit’s annual operating 

capacity. This means thatlevel of generation, for most NGCC 

units are being called to, would represent an increase in annual 

generation from a 2012 baseline emissions. .For every hour of 

electricity generated by an NGCC beyond its 2012 baseline (i.e.,

incremental generation), there is a corresponding emission 
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reduction in the power system.54 The EPA is proposing to reflect

the emission reductions of BB2 by crediting all NGCC generation 

on a pro-rata basis that reflects expected incremental NGCC 

generation to 75 percent capacity. This means that for every 

hour that an NGCC generates electricity, it will also generate a 

partial credit associated with the generation shift from fossil 

steam to NGCC units. The NGCC will generate a partial credit

because the emission reductions associated with BB2 have been 

distributed on an hourly basis. A discussion on the concepts 

behind the distribution of emission reductions of incremental 

NGCC generation on an hourly basis can be found at the end of 

this subsection. 

All affected NGCC generation will be credited, with ERCs,

by a factor that represents the described emission reductions 

from incremental generation; ERCs credited in this way will be 

designated as Gas Shift ERCs (GS-ERCs) for clarity55. The 

collective sum of the GS-ERCs generated realizes the amount of 

emission reductions described in BB2 when 75 percent capacity is 

 

54 It is assumed that any increase in NGCC generation above 2012 

levels is displacing fossil fuel-fired steam EGU generation.

55 A GS-ERC is treated and represents the same value as an ERC, but 

has a compliance restriction that it can only be used by steam 

generating units and not by stationary combustion turbines for 

compliance obligations.
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achieved. This incentive is not a requirement, however. If NGCC 

units do not collectively increase to 75 percent capacity or 

above, the lost opportunity for ERC generation simply will need 

to be achieved through other means (e.g., emissions performance 

improvements at affected EGUs or additional RE generation). The 

amount of GS-ERCs the EPA proposes to be generated for every MWh 

of NGCC operation is set at a factor relating the amount of 

electricity generation that NGCC units collectively would

generate at the level described in BB2 (i.e., reaching 75 

percent capacity) and the associated emission reductions. This 

means that fractional GS-ERCs are generated for every NGCC MWh 

and when the interconnect region collectively reaches the level 

that would be generated if all NGGCs in the region operated at a 

75 percent capacity factor there will be an amount of GS-ERCs 

that correlates to the emission reductionsanticipatedreductions

anticipated under BB2 of the BSER. NGCC units are expected to be 

incentivized to reach this level of generation in part due to

market demand for GS-ERCs. Thus, GS-ERCs have the potential to

play an important role in the sector meeting compliance 

obligations. 

The number of GS-ERCs that an NGCC generates is a 

combination of three factors. The first is the GS-ERC Emission 

Factor. This emission factor represents how much better an 
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individual NGCC’s emission rate is compared against the fossil 

steam standard. This measures the emission reductions because of 

the BB2 shift in generation. The steam generating unitSGU

standard used as reference here is as described above in section 

IV.B of this preamble and established in the BSER determination 

from the EGs of the least stringent region56 (i.e., the region 

with the highest calculated emission rate standard for steam 

generating units).SGUs). The GS-ERC Emission Factor is expressed 

by taking the complement of the ratio of the NGCC standard to 

the fossil-steam standard. It can be summarized by the following 

expression:

GS-ERC Emission Factor = 1 − NGCC emission rate

Steam Standard

The second factor is the Incremental Generation Factor. 

This factor represents the distribution of the increased NGCC 

generation across the all NGCC generation. In essence, it is 

prorating the incremental NGCC generation over all NGCC 

generation. The Incremental Generation Factor is calculated by 

taking the number of MWh beyond the 2012 baseline needed for the 

corresponding region to reach 75 percent NGCC generation 

 

56 The regions that are used in the CPP EGs and for this proposal 

are the Eastern Interconnect, Western Interconnect, and Electric 

Reliability Council of Texas (ERCOT). 
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capacity and dividing it by the the MWh that is 75 percent NGCC 

generation capacity, giving a factor. This factor can be 

summarized by the following expression:

Incremental Generation Factor = 1 − Regional 2012 NGCC Baseline

75 % NGCC Regional Capacity

The Incremental Generation Factor is a factor that the EPA will 

calculate and will be calculated for every compliance period

based on the least stingent region’s Incremental Generation 

Factor based on increased utilization of RE and its replacement 

of fossil fuel fired generation (based on Building Block 3 of 

the CPP EGs).57 For the calculation of this factor the EPA is 

using the least stringent region for each compliance period and 

applying it for all GS-ERC calculations subject to the federal 

plan. The calculations for determinating the least stringent 

regional Incremental Generation Factor can be found in the 

&&&GS-ERC TSD. Table 5. below are7 of this preamble presents the 

proposed values that would apply for all NGCC units to calculate 

the amount of issued GS-ERCs.

 

57 Note that per the discussion in section VI of the final EGs, 

if the EPA had measured incremental NGCC generation for 

reassignment to fossil steam rate as the difference from the 

post building block three levels and full utilization, the post 

building block three levels would be used in the numerator here, 

resulting in a higher “incremental generation factor” and more 

ERCs for the same amount of NGCC generation.
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Table 57. Incremental Generation Factors for Interim and Final 

Compliance Periods 

Corresponding Incremental Generation Factor 

Compliance 

Period 1 

2022-2024

Compliance 

Period 2 

2025-2027

Compliance 

Period 3 

2028-2029

2030-2031

and thereafter

0.22 0.32 0.28 0.26

The third factor in calculating an NGCC’s generaton of GSERC is the NGCC Generation. The NGCC Generation is the total net 

energy output generation of the affected NGCC during the year 

that ERCs are being calculated. The three factors combine to 

make the following equation:

GS-ERCs = NGCC Generation * Incremental Generation Factor * GS-ERC Emission Factor

The GS-ERC equation above gives the number of GS-ERCs that an 

NGCC will generate. The Incremental Generation Factor and GS-ERC 

Emission Factor combine to make the GS-ERC generating rate for 

the NGCC. This functions by the Incremental Generation Factor 

prorating all incremental NGCC generation and the GS-ERC 

Emission Factor designating the proportion of the incremental 

NGCC generation that will generate ERCs. The GS-ERC generating 

rate multiplied by the total NGCC Generation gives the total GSERCs generated by the NGCC for the year.

The EPA is proposing this approach, which provides GS-ERCs 

for all affected EGU NGCC generation but at a fractional, pro 

rated level, using the three factors above, for several reasons. 
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This approach has the benefit of allowing NGCC units to bid into 

the electricity market without having to adjust bids based on a 

projection of whether or not the NGCC will have generation 

incremental to its baseline in a given year. The proposed method 

also promotes the best performers within the NGCC subcategory by 

crediting them with a higher rate of generating GS-ERCs, as 

shown by the calculations above. The better the emission 

performance of an NGCC unit, the more GS-ERCs it is capable of 

earning per MWh. The proposed method also promotes and 

incentivizes all NGCC units, regardless of historical 

generation, to continue to operate at a greater capacity to 

replace steam generation. The EPA believes that this will allow 

for more fluidity in the market and flexibility for greater NGCC 

generation.

In the CPP EGs theClean Power Planthe BSER determination 

for subcategory rates is calculated by using the least stringent 

region and applying the standards from that region on a national 

level. The determination of the BSER in the final EGs was a onetime determination and is not being altered, updated, or changed 

here. Rather, in this preamble the EPA is proposing to use the 

same regions and to apply the least stringent components to an 

NGCC’s GS-ERC calculation at a national level (i.e., applying 

the GS-ERC calculation components that generate the most GS-ERCs 
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for every MWh). The EPA solicits comment on applying the least 

stringent regional factor to calculate GS-ERCs for all affected 

NGCC units subject to the federal plan and model rule on a

national level. Conversely, the EPA also requests comment on 

applying, for each region, its own regional GS-ERC generation 

rate. As proposed, the least stringent region could change from 

compliance period to compliance period. The EPA requests comment 

on whether a single “least stringent” region should be chosen 

and used for calculations or whether being “least stringent” 

should be evaluated on a compliance period by compliance period 

basis. The EPA also requests comment on whether “least 

stringent” should be evaluated on a year to year basis. 

The EPA also requests comment on whether the GS-ERC 

Emission Factor should be calculated on a unit by unit basis (as 

currently proposed) or be calculated based on the least 

stringent region’s baseline 2012 average emission rate. This 

will simplify the practice of calculating and distributing GSERC generation, but would not reward the better performing NGCC 

units within the subcategory. In the &&&GS-ERC TSD, the EPA used 

the regions’ average emission rate to calculate a factor that 

would credit GS-ERCs to all NGCC units subject to the federal 

plan. For 2030 and beyond, this value is based on the Eastern 

Interconnect and is 0.08 GS-ERCs/MWh. So for every MWh that an 
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NGCC generates it would be issued 0.08 GS-ERCs and, if this were 

the approach the EPA proposed, this would apply to every NGCC 

that would be subject to the federal plan. 

In the &&&&GS-ERC TSD, the spreadsheet can be manipulated 

to show what an individual NGCC’s GS-ERC Emission Factor would 

be in the proposed method. This is done by adjusting the cell

for a year’s Average GS-ERC Emission Factor to account for the 

individual NGCC’s emission rate instead of the average NGCC 

emission rate.

The calculation of GS-ERCs for an NGCC is independent of 

the calculation of ERCs generated or owed against the NGCC 

standard. It is possible that an NGCC will owe ERCs against its

assigned emission standard for every MWh generated, but still be 

generating GS-ERCs. GS-ERCs may only be used to meet steam 

generation units’ compliance obligations.

As an example, an NGCC is connected to the grid and 

generates 1 million MWh of electric output for the first year of 

the final performance period. During this year it emits 850 

million lbs of CO2 giving it an emission rate of 850 lbs CO2/MWh. 

The NGCC is subject to a final period emission rate limit of 771

lbs CO2/MWh. Since the NGCC is always subject to its NGCC

emission rate standard of 771 lbs/MWh and it is operating at a 

rate above that standard it will owe non GS-ERCs for its own 
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compliance. The ERCs owed are calculated by solving for the 

number of ERC MWh the NGCC will need to adjust its rate down to 

its emission rate limit. This is shown in the following 

equation:

850,000,000 lbs CO2 / [1,000,000 MWh + ERC MWh] = 771 lbs CO2/MWh

When that equation is solved for the number of ERC MWh needed, 

the NGCC would need to acquire 102,464 ERCs to adjust its 

emission rate to its emission rate standard.

Additionally, the GS-ERC Emission Factor for this NGCC is 

calculated by using 771 lbs CO2/MWh for the NGCC emission rate 

and 1,404 lbs CO2/MWh for the steam generating unitSGU emission 

standard in the equation described above. 

GS-ERC Emission Factor = 1 − 771 lbs/MWh

1,404 lbs/MWh

This calculation results in a GS-ERC Emission Factor of 0.45. 

This is only an example. Because the Incremental Generation 

Factor is calculated by the EPA, it can be found in the &&&GSERC TSD and is proposed to be 0.26. By using the GS-ERC Emission 

Factor and Incremental Generation Factor calculated above with 

the NGCC’s generation for the year, the number of GS-ERCs for 

this NGCC can be calculated. 

0.45 ∗ 0.26 ∗ 1,000,000 = GS-ERC

The calculation results in 117 thousand GS-ERCs being generated. 
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Because an NGCC cannot use the GS-ERCs it generates to meet its 

compliance obligations, this NGCC will both generate ERCs 

(117,000 GS-ERCs) and owe ERCs (102,464 non-GS-ERCs against NGCC 

standard). This NGCC may sell (or otherwise transfer) or bank 

its GS-ERCs. If a GS-ERC is sold, those proceeds may, in turn, 

be used to acquire non-GS-ERCs to satisfy the NGCC’s compliance 

obligations.

A GS-ERC may not be used to meet an NGCC’s compliance 

obligation because they are generated to reflect incremental 

NGCC generation replacing a steam generating unit’sSGU’s

generation. The calculation to derive a GS-ERC represents this 

generation shift. If a GS-ERC were to be used for compliance for 

an NGCC it would represent a shift from one NGCC to another, 

which serves little purpose in achieving emission reductions.

The EPA requests comment on the proposed approach and 

requests comment and suggestions on other approaches for 

existing NGCC units to generate GS-ERCs at all times. The EPA is 

considering this methodology that GS-ERCs are generated for all 

NGCC generation because it ensures that all existing NGCC units

are encouraged to run at a greater capacity. The EPA is 

requesting comment on alternative methods to account for NGCC 

units generating GS-ERCs. Specifically, the EPA solicits comment 

on NGCC units generating GS-ERCs once a threshold of electric 
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generation for the year is exceeded. This threshold is based on 

2012 as a baseline and any NGCC generation beyond this threshold 

would be considered incremental generation. There are two 

different options to evaluate against a baseline. The first is 

on a unit level, if aan NGCC generates more than it did in 2012, 

all generation above the 2012 level (i.e, incremental 

generation) is eligible to be credited with GS-ERCs. The other 

threshold option is to use a percentage threshold. Evaluated on 

a regional level, the 2012 baseline capacity percentage for NGCC 

units in the least stringent region is applied to all units. 

Each unit is considered to be incrementally generating after it 

exceeds the capacity percent and will be credited with GS-ERCs 

accordingly. The GS-ERCs in these instances are calculated by 

the following equation: 

GS-ERC = (Steam standard − NGCC emission rate)

Steam standard ∗ Incremental NGCC generation

This equation quantifies the reductions of the generation 

shift from fossil steam to NGCC units by the NGCC operating rate 

being evaluated against the fossil steam standard. For all 

incremental NGCC generation the NGCC operating rate is compared 

against two different standards: (1) The NGCC standard against 

which ERC generation is evaluated; and (2) the steam standard 

against which GS-ERC generation is evaluated. An evaluation 
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against each standard is independent of one another and GS-ERCs, 

in this situation, are only available for fossil steam 

compliance purposes.

While having a baseline threshold for EGU generation to 

credit GS-ERCs against closely resembles the EPA’s BSER 

determination, it enables a system in which GS-ERCs can be 

generated by replacing NGCC generation from one unit with NGCC 

generation from another. In this situation there is not 

necessarily any additional NGCC generation as a subcategory, but 

a shift in which NGCC units are generating electricity and to 

what degree. This allows for a situation in which GS-ERCs can be 

generated without achieving the anticipated reductions in CO2

emissions.

The EPA also requests comment on whether a distinct type 

of ERC that comes with the proposed restrictions (i.e., GS-ERCs) 

is necessary to maintain the integrity of the rate-based trading

proposal... Comments regarding this section that solely relate 

to determinations finalized in the EGs will be considered out 

ofoutside the scope of this proposed rule.

3. Eligible Emission Reduction Measures for ERC Generation

Under the rate-based federal plan, the EPA is proposing to 

specify emission reductions measures used to adjust an emission 

rate that are eligible for ERC issuance under the federal plan. 
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Specifically, the EPA is proposing that RE generation that meets 

the requirements for eligible resources in the emission 

guidelines,EGs (as specified in section VIII.K of the final 

EGs), meets all other requirements related to ERC issuance in 

the emission guidelinesEGs and this proposal, and falls into one 

of the following specific categories of RE resources (as 

specified in section V.E of the final guidelines Sec.V.E.)EGs)

are eligible to be issued ERCs: on-shore wind, solar

photovoltaics (PV), concentrated solar power, geothermal power, 

and hydropower.58 Further, the EPA is proposing for the federal 

plan that new nuclear units and capacity uprates at existing 

nuclear units that meet the requirements for eligible resources 

in the emission guidelinesEGs (as specified in section VIII.K of 

the final emission guidelines Sec.VIII.K.)EGs) and all other 

requirements related to ERC issuance in the emission 

 

58 This treatment for RE as an eligible measure type is also 

proposed for the set-aside for RE that is part of the proposed 

mass-based implementation approach co-proposed in section V of 

this preamble as the federal plan, and all proposed aspects of the 

eligible measure types described in this section and the requests 

for comment included below also apply in the mass-based set-aside 

context. Incremental nuclear is not eligible for the RE set-aside. 

The set-aside method and the use of this eligibility treatment 

within it are specified in section V.D.3 of this preamble.
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guidelinesEGs and this proposal are eligible to generate ERCs. 

Further, these RE and nuclear measures must have the ability to 

provide data from a revenue quality meter, a requirement 

whichthat is further discussed in Sec.section IV.D.8 and Sec.

IV.G.4below of this preamble.

The EPA is proposing the inclusion of these measure types

in the federal plan for the following reasons. These 

technologies, with the exception of nuclear, are part of the 

quantification of renewable energyRE generation potential for 

the BSER. Thus, they are included in the quantification of CO2

emission performance rates and should be available to affected 

EGUs to meet their CO2 emission performance rate under the 

federal plan,. See the final guidelinesEGs for details on the 

treatment of these measures in BSER (see Sec.section V.E.). of 

the final EGs). These technologies are also expected to be able 

to deploy on an economic basis during the compliance period, as 

discussed in the final EGs (see Sec.section V.E.6 of the final 

EGs). These technologies also provide the simplest and most 

timely path for evaluation, measurement, and verification (EM&V)

implementation under a federal plan, asbecause they can use

their existing metering infrastructure to quantify generation

and submit it for ERC issuance. A unique concern unique to 

federal plan implementation is the need for an ERC issuance 
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process that can be implemented in a streamlined manner across 

many jurisdictions in the time frame allowed by the federal plan

while still assuring a rigorous EM&V process. By limiting 

eligibility to measures that can be directly metered, a feasible 

federal plan process for ERC issuance across a potentially large 

number of jurisdictions is ensured. This approach would allow 

for easier determinations of compliance with the requirements 

for EM&V proposed in section IV.&&&.D.8 of this preamble below

(see also section VIII.&&&.K.3 of the final EGs).

The agency requests comment on the inclusion of other 

emission reduction measures as eligible for ERC issuance under 

the rate-based federal plan. This may include other RE 

technologies not included above, such as distributed RE 

generation and various types of biomass. In this proposal, the 

EPA is also offering for comment treatment options for biomass 

fuels, if it is included as an eligible measure under the 

federal plan (see below.).

The EPA requests comment on the inclusion of various types 

of demand-side EE as eligible measures for ERC issuance under 

the federal plan, such as state and utility EE programs, 

project-based demand-side EE, state building codes, state 

appliance standards, and conservation voltage reduction. The 

agency also requests comment on the inclusion of combined heat 
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and power (CHP) as an eligible measureCHP as an eligible measure

under the federal plan. Later in this section, the agency has 

provided detailed requirements for the issuance of ERCs for CHP, 

and we request comment on these requirements for inclusion in 

the federal plan. 

The EPA requests comment on the inclusion as eligible for 

ERC issuance under the federal plan of any other emission 

reduction measures beyond those mentioned here, as long as they 

meet the eligibility requirements outlined in the final EGs for 

rate-based crediting. For all of the above measures on which the 

EPA requests comment, the agency is particularly interested in 

comments on how EM&V methods can be implemented for these 

measures across applicable jurisdictions in the timeframe 

provided by this proposal in a way that is rigorous, 

straightforward, widely demonstrated, and in accordance with the 

EM&V requirements in this proposal, outlined in Sec. &&&,section 

IV.D.8 of this preamble, and within the requirements outlined in 

the final guidelines (see Sec.section VIII.G.5K.3 of the final 

EGs). It should also be noted that any eligible measure will be 

subject to the eligibility requirements outlined in this 

proposal and the final EGs, such as the requirement that the 

measure be incremental to 2012.

The EPA acknowledges that as new technologies mature, there 
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should be an avenue to add new technologies to this specified 

set of eligible measures. under the federal plan. The agency is 

requesting comment on appropriate processes through which, after 

the federal plan is finalized, the EPA and/or stakeholders could 

make a demonstration ofdemonstrate the appropriateness of new 

measure types and the EPA could evaluate and approve the 

demonstration so that a new measure type cancould be considered 

eligible for ERC issuance under the federal plan.

Under the rate-based model rule, the EPA is proposing that 

any emission reduction measure is eligible as long as the 

requirements for eligible resources in the final EGs (as 

specified in section VIII.K of the final EGs) and all other 

requirements related to ERC issuance under the model rule that 

are specified in the EGs and this proposal. In particular, these 

measures should be able to meet the requirements for EM&V as 

finalized in the final EGs section VIII.K and those proposed for 

the model rule in section IV.D.8 of this proposal. In this 

section, the EPA is also providing detailed requirements for CHP 

and waste heat power (WHP), these requirements are proposed 

under the model rule, and we request comment on their inclusion 

in the federal plan. We are requesting comment on the inclusion 

of biomass and an option for the treatment of biomass in both 

the proposed rate-based federal plan and proposed rate-based 
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model rule.

As mentioned above, the EPA is requesting comment on the 

inclusion of biomass as an eligible measure for rate-based 

crediting. The EPA is also requesting comment on the following 

treatment options for biomass if biomass is included as an 

eligible measure. In the final emissions guidelinesEGs, the EPA 

recognizes that the use of some biomass-derived fuels can play 

an important role in controlling increases of CO2 levels in the 

atmosphere (see Sec. I.2.c).section V.A.6 of the final EGs). The 

use of some kinds of biomass has the potential to offer a wide 

range of environmental benefits, including carbon benefits. 

However these benefits can typically only be realized only if 

biomass feedstocks are sourced responsibly and attributes of the 

carbon cycle related to the biomass feedstock are taken into 

account. Many states have already recognized the importance of 

waste-derived feedstocks via mandatory and voluntary programs 

supporting such efforts.59 Some states have also acknowledged the 

 

59 Types of waste-derived biogenic feedstocks may include: landfill 

gas generated through the decomposition of Municipal Solid Waste 

(MSW) in a landfill; biogas generated from the decomposition of 

livestock waste, biogenic MSW, and/or other food waste in an 

anaerobic digester; biogas generated through the treatment of 

waste water, due to the anaerobic decomposition of biological 

materials; livestock waste; and the biogenic fraction of MSW at 
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potential role of certain forestry and agricultural industrial 

byproducts (such as black liquor) in energy production. Many 

states have also recognized the importance of forests and other 

lands for climate resilience and mitigation, and have developed 

a variety of sustainable forestry policies, biomass-related 

renewable energyRE incentives and standards, and GHG accounting 

procedures.60

In addition to acknowledging such state programs, the EPA 

has undertaken a technical assessment of biogenic CO2 emissions 

from stationary sources associated with the production, 

processing and use of biomass fuels. In November 2014, the 

agency released a second draft of the technical report, 

Framework for Assessing Biogenic Carbon Dioxide for Stationary 

 

waste-to-energy facilities (as discussed in section VIII.I.2.C of 

the final EGs).

60 Some states, for example Oregon and California, have programs 

that recognize the multiple benefits that forests provide, 

including biodiversity and ecosystem services protection as well 

as climate change mitigation through carbon storage. Others, like 

California’s Forest Practice Regulations, support sustained 

production of high-quality timber while considering ecological, 

economic and social values. Several states focus on sustainable 

bioenergy, as seen with the sustainability requirements for 

eligible biomass in the Massachusetts RPS, which, among other 

requirements, limits old growth forest harvests.
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Sources. The revised Framework, and the EPA’s Science Advisory 

Board (SAB) peer review of the 2011 Draft Framework, 

findsconcluded that it is not scientifically valid to assume 

that all biogenic feedstocks are “carbon neutral” and that the 

net biogenic CO2 atmospheric contribution of different biogenic 

feedstocks generally depends on various factors related to 

feedstock characteristics, production, processing and combustion 

practices, and, in some cases, what would happen to that 

feedstock and the related biogenic emissions if not used for 

energy production.61The EPA is engaging in a second round of 

targeted peer review on the revised Framework with the SAB in 

2015.62 Information in the revised Framework and the second SAB 

peer review process, including stakeholder comments, will assist 

 

61Specifically, the SAB found that “There are circumstances in 

which biomass is grown, harvested and combusted in a carbon neutral 

fashion but carbon neutrality is not an appropriate a priori 

assumption; it is a conclusion that should be reached only after 

considering a particular feedstock’s production and consumption 

cycle. There is considerable heterogeneity in feedstock types, 

sources and production methods and thus net biogenic carbon 

emissions will vary considerably. Of course, biogenic feedstocks 

that displace fossil fuels do not have to be carbon neutral to be 

better than fossil fuels in terms of their climate impact.”

http://www.epa.gov/climatechange/ghgemissions/biogenicemissions.html.

62 http://www.epa.gov/sab. 
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the EPA in assessing potential qualifyingqualified biomass 

feedstocks in federal plan applications. 

If biomass is included as an eligible measure, we are 

taking comment on an option for biomass treatment under the 

rate-based federal plan, which would also apply to eligible 

generation under the mass-based plan allowance set-aside and to 

the calculation of covered emissions for affected EGUs that are 

co-firing biomass.

This option offered for comment is to specify a list of 

pre-approved qualified biomass fuels. For example, the EPA could 

recognize the CO2 and climate policy benefits of waste-derived 

feedstocks (e.g., landfill gas) and certain industrial byproduct 

feedstocks (such ase.g., black liquor or other forestry and 

agricultural industrial byproducts with no alternative markets).

As another example, the EPA could also recognize biomass 

feedstocks from sustainably managed forests lands, provided that 

these feedstocks meet certain requirements. The pre-approved 

qualified such as demonstration that the feedstock is sourced 

from sustainably managed lands (for example, feedstocks from 

forest lands with sustainable practices like improved management 

to increase carbon sequestration benefits) and therefore helps

control increases of CO2 in the atmosphere. The pre-approved 

qualified biomass feedstocks list could be amended in the future 
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as the science related to biogenic CO2 emissions assessments 

evolves. The EPA asks for comment on whether to include a 

provision that allows sources to seek approval for other types 

of biomass to be added to the pre-approved list and what that 

process would entail. For example, this process could include 

consideration of the production, processing and use of forestand agriculture-derived biomass fuels and related CO2 benefits.

The EPA also requests comment on options for 

demonstratinghow EGUs would demonstrate that feedstocks meet the 

requirements to be accepted as a pre-approved qualified biomass 

feedstocks. These requirements could include demonstration of 

certification or verification of practices that are additional 

to other monitoring, reporting and EM&V requirements discussed 

in this proposal, such as provision of sufficient credible 

analysis of carbon benefits, third party verification and/or 

certification, or a determination of the net biogenic CO2 effects 

related to the production, processing and use of the feedstock. 

We takeThe EPA requests broad comment on the types of 

qualifyingqualified biomass feedstocks that should be specified 

in the final model rule, if any. We takerequest comment on the 

methods that we should specify in the final model rule for the 

measurement of the associated biogenic CO2 for such feedstocks, 

as well as what other requirements we should specify in the 
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final model rule related to biomass. Specifically, we seek 

comment on the level of detail provided and whether more or less 

detail (and what detail) should be included in the final model 

rule. We takerequest comment on any other requirements that 

should be included in the final model rule regarding EM&V for 

qualifyingqualified biomass. Discussion of the biomass EM&V 

requirements in the rate-based model rule can be found in 

Sec.section IV.D.8 of this preamble below. 

The eligibility requirements for ERC resources discussed in 

this section meet the requirements outlined in the final EGs

(see Final EGs preamble section VIII.G.1.bK.2 of the final EGs).

The agency in this proposal is including in the regulatory text 

for the model rule language related to the crediting of these 

other potential ERC resources, even though they are not being 

proposed as a part of the federal plan. ThisOur intent is in 

order to provide states further direction through the model rule 

on how states may include this broader set of ERC-generating 

resources in a rate-based plan. To reduce confusion over the 

applicability of these provisions, the agency has added a note 

in the regulatory text to clarify that these resources, and 

provisions throughout the proposed subpart that are related to 

those resources, are not applicable in the case of a federal 

plan. Rather they are proposed as part of the model trading rule 
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only. However, again, the agency is requesting comment on the 

inclusion of these resources in the federal plan. 

The EPA is proposing with respect to the rate-based model 

rule that CHP units are eligible to generate ERCs. With respect to 

the federal plan, the EPA is requesting comment on the 

incorporation of non-affected CHP units. Electric generation from 

non-affected CHP units63 may be used to adjust the CO2 emission 

rate of an affected EGU, as CHP units are low-emitting electric 

generating resources that can replace generation from affected 

EGUs. Electrical generation from non-affected CHP units that meet 

the eligibility criteria under section VIII.K.1.a of the Clean 

Power Plan preamble can be used to adjust the reported CO2 emission 

rate of an affected EGU.

 

63 The accounting treatment described in this section is for a 

“topping cycle” CHP unit. A topping cycle CHP unit refers to a 

configuration where fuel is first used to generate electricity and 

then heat is recovered from the electric generation process to 

provide additional useful thermal and/or mechanical energy. A CHP 

unit can also be configured as a “bottoming cycle” unit. In a 

bottoming cycle CHP unit, fuel is first used to provide thermal 

energy for an industrial process and the waste heat from that 

process is then used to generate electricity. Some waste heat power 

(WHP) units are also bottoming cycle units and the accounting 

treatment for bottoming cycle CHP units is provided with the WHP 

description below.
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The electrical generation from a non-affected CHP unit that 

can be used to adjust the CO2 emission rate of an affected EGU must 

be calculated in accordance with the method specified in this 

section. The CHP unit’s electrical output is prorated based on the 

CO2 emission rate of the electrical output associated with the CHP 

unit (a CHP unit’s “incremental CO2 emission rate”) compared to a 

reference CO2 emission rate.64 This “incremental CO2 emission rate” 

related to the electric generation from the CHP unit would be 

relative to the applicable CO2 emission rate standard for affected 

EGUs in the state and would be limited to values between 0 and 1. 

The CHP unit’s electrical output is prorated as follows:

Prorated MWh = (1-incremental CHP electrical emission 

rate/applicable affected EGU emission rate standard)* CHP MWh 

output

Where the ratio is limited to values between 0 and 1.

The CHP electrical CO2 emission rate is the net emission rate 

when the CHP unit’s CO2 emissions related to its thermal output 

are deducted from the CHP unit’s total CO2 emissions. The CHP 

electrical CO2 emission rate is derived as follows:

 

64 The applicable CO2 emission rate standard is in Table 6. of this 

preamble.
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CHP electrical CO2 emission rate = [CHP fuel input65 * fuel 

emission factor66 – (UTO/boiler efficiency) * fuel emission 

factor]/CHP electrical MWh

Where UTO is the useful thermal output from a 

counterfactual industrial boiler that would have existed to 

meet thermal load in the absence of the CHP unit.

This accounting approach takes into account the fact that a 

non-affected CHP unit is a fossil fuel-fired emission source, as 

well as the fact that the incremental CO2 emissions related to 

electrical generation from a non-affected CHP unit are typically 

very low. To generate ERCs for CHP, the CHP Electrical CO2 Emission 

Rate that is calculated (from above) is applied against the 

applicable affected EGU standards in the same fashion as described 

in section IV.C.1 of this preamble. The low CO2 emission rate for 

electrical generation from a non-affected CHP unit is a product of 

both the fact that CHP units are typically very thermally efficient 

and the fact that a portion of the CO2 emissions from a nonaffected CHP unit would have occurred anyway from an industrial 

boiler used to meet the thermal load in the absence of the CHP 

 

65 This term generally represents the thermal energy associated 

with the total fuel input.

66 The fuel emission factor can be determined through 40 CFR Part 

75 Appendix G. 
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unit. In contrast, the CHP unit also provides the benefit of 

electricity generation while resulting in very low incremental CO2

emissions beyond what would have been emitted by an industrial 

boiler. As a result, the accounting method does not presume that 

emission reductions occur outside the electric power sector, but 

instead only accounts for the CO2 emissions related to the 

electrical production from a CHP unit that is used to substitute 

for electrical generation from affected EGUs.

The EPA is proposing with respect to the rate-based model 

rule that WHP units are eligible to generate ERCs. With respect to 

the federal plan, the EPA is requesting comment on the 

incorporation of non-affected WHP units. WHP units that meet the 

eligibility criteria under section VIII.K.1 of the Clean Power 

Plan preamble may be used to adjust the CO2 emission rate of an 

affected EGU. There are several types of WHP units. There are 

units, also referred to as bottoming cycle CHP units, where the 

fuel is first used to provide thermal energy for an industrial 

process and the waste heat from that process is then used to 

generate electricity.67 There are also WHP facilities where the 

waste heat from the initial combustion process is used to generate 

 

67 In such a configuration, the waste heat stream could also be 

generated from a mechanical process, such as at natural gas 

pipeline compressors.
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additional power. Under both configurations, unless the WHP unit 

supplements waste heat with fossil fuel use, there is no additional 

fossil fuel used to generate this additional power. As a result, 

there are no incremental CO2 emissions associated with that 

additional power generation. As a result, the incremental electric 

generation output from the WHP facilities could be considered nonemitting, for the purposes of meeting the emission guidelines, and 

the MWh of electrical output could be used to adjust the CO2

emission rate of an affected EGU.68 The MWh of electrical output 

from a WHP unit that can be recognized may not exceed the MWh of 

industrial or other thermal load that is being met by the WHP unit, 

prior to the generation of electricity.69In addition, where fossil 

fuel is used to supplement waste heat in a WHP application, the 

EPA requests comment on what provisions to include in the final 

model rule to prorate the proportion of fossil fuel heat input to 

 

68 This only applies where no additional fossil fuel is used to 

supplement the use of waste heat in a WHP facility. Where fossil 

fuel is used to supplement waste heat in a WHP application, MWh of 

electrical generation that can be used to adjust the CO2 emission 

rate of an affected EGU must be prorated based on the proportion 

of fossil fuel heat input to total heat input that is used by the 

WHP unit to generate electricity.

69 This limitation prevents oversizing the thermal output of a WHP 

unit to exceed the useful industrial or other thermal load it is 

meeting, prior to generation of electricity.
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total heat input that is used by the WHP unit to generate 

electricity. The EPA also solicits comments on other potential 

accounting mechanisms for WHP. As noted above, the EPA requests 

comment incorporating WHP as an ERC generating resource for the 

federal plan.

D. ERC Tracking and Compliance Operations

The EPA proposes that the rate-based federal trading 

program use the agency’s already-existing allowance tracking and 

compliance system (ATCS). Under the proposed rate-based trading 

program, the federal trading program would be maintained in the 

EPA’s existing data system. The ATCS would be used to track the 

trading of ERCs held by affected EGUs, as well as ERCs held by 

other entities. Specifically, the ATCS would track the 

generation of ERCs, holdings of ERCs in compliance accounts 

(i.e., accounts for affected EGUs) and general accounts (i.e.,

accounts for other entities and for affected EGUs, including 

affected EGUs that are under a ready-for-interstate-trading

state plan), deduction of ERCs for compliance purposes, and 

transfers of ERCs between accounts. The primary role of the ATCS

is to provide an efficient, automated means for covered sources 

to comply, and for the EPA to determine whether covered sources 

are complying, with the emissions rate standards. The ATCS would 

also provide data to the ERCs market and the public, including a 
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record of ownership of ERCs, dates of ERC issuance, ERC 

transfers, buyer and seller information, serial numbers of ERCs 

transferred, emissions, and compliance information. This 

information would be publicly available on the EPA’s Web site 

and in annual progress reports. The ATCS and the EPA provide all 

required elements of a qualified ERC tracking system as 

described in section VIII of the CPPfinal EGs.

In the subsections that follow, the mechanisms by which a

rate-based trading program would be implemented and administered 

are detailed. The EPA requests comment on each component of the 

trading system that is proposed in this preamble and the 

associated model rule, the trading program as a whole, and 

specifically requests comment on means to expedite the process 

of issuing ERCs, any minimum and maximum periods for which ERCs 

should be issued (e.g., monthly, quarterly, annually), and any

means to insureensure that the ERCs issued meet the requirements 

of the emission guidelinesEGs and these proposed rules. The

rate-based federal plan and model rule borrow many concepts from 

other successful trading programs, and the agency is interested 

in receiving additional information through comments on 

successful implementation of similar programs. 
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1. Designated Representatives and Alternate Designated 

Representatives 

This section establishes the procedures for certifying and 

authorizing the designated representative, and alternate 

designated representative, of the owners and operators of the 

affected EGU and for changing the designated representative and 

alternate designated representative. These sections also 

describe the designated representative’s and alternate 

designated representative’s responsibilities and the process 

through which he or she could delegate to an agent the authority 

to make electronic submissions to the Administrator. These 

provisions would be patterned after the provisions concerning 

designated representatives and alternates in prior EPAadministered trading programs. 

The designated representative would be the individual 

authorized to represent the owners and operators of each 

affected EGU in matters pertaining to the rate-based trading 

program. One alternate designated representative could be 

selected to act on behalf of, and legally bind, the designated 

representative and, thus, the owners and operators. Because the 

actions of the designated representative and alternate would 

legally bind the owners and operators, the designated 

representative and alternate would have to submit a certificate 
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of representation certifying that each was selected by an 

agreement binding on all such owners and operators and was 

authorized to act on their behalf.

The designated representative and alternate would be 

authorized upon receipt by the Administrator of the certificate 

of representation. This document, in a format prescribed by the 

Administrator, would include: specified identifying information 

for the covered source and covered electric generating unitsEGUs

at the source and for the designated representative and 

alternate; the name of every owner and operator of the affected 

EGU; and certification language and signatures of the designated 

representative and alternate. All submissions (e.g., monitoring 

plans, monitoring system certifications, and allowance 

transfers) for an affected EGU would have to be submitted, 

signed, and certified by the designated representative or 

alternate. Further, upon receipt of a complete certificate of 

representation, the Administrator would establish a compliance 

account in the ATCS for the affected EGU involved.

In order to change the designated representative or 

alternate, a new certificate of representation would have to be 

received by the Administrator. A new certificate of 

representation would also have to be submitted to reflect 

changes in the owners and operators of the affected EGU
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involved. However, new owners and operators would be bound by 

the existing certificate of representation even in the absence 

of such a submission.

In addition to the flexibility provided by allowing an 

alternate to act for the designated representative (e.g., in 

circumstances where the designated representative might be 

unavailable), additional flexibility would be provided by 

allowing the designated representative and alternate to delegate 

authority to make electronic submissions on his or her behalf.

The designated representative and alternate could designate 

agents to submit electronically certain specified documents. The 

previously-described requirements for designated representatives 

and alternates would provide regulated entities with flexibility 

in assigning responsibilities under the rate-based trading 

program, while ensuring accountability by owners and operators 

and simplifying the administration of the proposed rate-based 

trading program. 

2. ERC Tracking and Compliance System 

The rate-based trading program rules establish the 

procedures and requirements for using and operating the 

Allowance Tracking and Compliance System (which is the 

electronic data system through which the Administrator would 

handle ERC issuance, holding, transfer, and deduction), and for 
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determining compliance with the ERC-holding requirements in an 

efficient and transparent manner. The ATCS provides a record of 

ownership, dates of ERC transfers, buyer and seller information, 

origin of ERCs, the serial numbers of ERCs transferred, and ERC 

type (i.e., if it is a GS-ERC or not). ERC price information 

would not be included in the ATCS. The EPA’s experience is that 

private parties (e.g., brokers) are in a better position to 

obtain and disseminate timely, accurate price information than 

is the EPA. For example, because not all ERC transfers are 

immediately reported to the Administrator for recordation, the 

Administrator would not be able to ensure that any reported 

price information associated with the transfers would reflect 

current market prices.

3. Tracking System Requirements

This federal plan and model rule’s proposed tracking system 

and tracking systems that will be presumptively approvable for 

state plans fufill the criteria set forth in the final EGs. The 

EPA’s tracking system includes provisions to ensure that ERCs 

issued to any eligible entity are properly tracked from issuance 

to submission by affected EGUs for compliance (where ERCs are 

“surrendered” by the owner or operator of an affected EGU and 

“retired” or “cancelled” by the Administrator or administering

state regulatory body), to ensure they areareused only used once 
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to meet a regulatory obligation. This is addressed through 

specified requirements for tracking system account holders, ERC 

issuance, ERC transfers among accounts, compliance true-up for 

affected EGUs,70 and an accompanying tracking system 

infrastructure design. Each issued ERC will have a unique 

identifier (i.e., serial number) and the tracking system will

provide traceability of issued ERCs back to the program or 

project for which they were issued. 

The EPA received a number of comments from states and 

stakeholders inon the CPP EGs aboutClean Power Planabout the 

value of the EPA’s support in developing and/or administering 

tracking systems to support state administration of rate-based 

emission trading systems. As described above in section III.A of 

this preamble, the EPA is proposing, as part of both types of 

model trading rules, a federal trading platform that would allow 

state plans that are ready-for-interstate-trading to operate 

through a program in which the EPA provides the tracking and 

compliance system. This system will meet the requirements of the 

CPP EGsClean Power Plan.

 

70 “Compliance true-up” refers to ERC submission by an owner or 

operator of an affected EGU to adjust a reported CO2 emission rate, 

and determination of whether the adjusted rate is equal to or lower 

than the applicable rate-based emission limit.
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4. Compliance and General Accounts

This section describes two types of ATCS accounts: 

compliance accounts, one of which would be established by the 

Administrator would establish for each affected EGU upon receipt 

of the certificate of representation for the source; and general 

accounts, which could be established by any entity upon receipt 

by the Administrator of an application for a general account. A 

compliance account would be the account in which any ERCs used 

by the affected EGU for compliance with the emissions 

limitations would have to be held until retired for compliance.

General accounts could be used by any person or group for 

holding or trading ERCs. However, ERCs could not be used for 

compliance with emissions limitations so long as the ERCs were 

held in, and not properly and timely transferred out of, a 

general account. To open a general account, a person or group 

would havebe required to submit an application for a general 

account, which would be similar in many ways to a certificate of 

representation. The application would include, in a format to be 

prescribed by the Administrator: The name and identifying 

information of the individual who would be the authorized 

account representative and of any individual who would be the 

alternate authorized account representative; an identifying name 

for the account; the names of all persons with an ownership 
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interest with the respect to allowances held in the account; and 

certification language and signatures of the authorized account 

representative and alternate. The authorized account 

representative and alternate would be authorized upon receipt of 

the application by the Administrator. The provisions for 

changing the authorized account representative and alternate, 

for changing the application to take account of changes in the 

persons having an ownership interest with respect to ERCs, and 

for delegating authority to make electronic submissions would be 

analogous to those applicable to comparable matters for 

designated representatives and alternates. The EPA requests 

comment on these compliance mechanisms. 

5. Compliance Demonstration

The EPA proposes that affected EGUs subject to this federal 

plan are required to meet compliance obligations by November 1 

of the year following the end of the compliance period. For an 

affected EGU to meet its compliance obligations its average 

stack emission rate over the compliance period must be at or 

below its applicable rate standard, or the affected EGU must use 

ERCs to adjust its average stack emission rate to be at or below 

its applicable rate standard. An EGU’s average emission rate 

over the compliance period will be calculated based on submitted 

data to ATCS. The compliance period average would be calculated 
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by taking the measured CO2 mass in units of pounds (lbs) summed 

over the compliance period for an affected EGU and dividing it 

by the total net energy output over the compliance period for 

that affected EGU in units of MWh.71 This averaged emission rate 

will be compared to the emissions standards that the EGU is 

subject to during the corresponding compliance period. 

Accordingly, and if necessary, the appropriate number of ERCs 

will be retired from the EGU’s compliance account to adjust the 

emission rate of the EGU to be equal to the emission standard. 

The discussion of using ERCs for compliance is found in section 

IV.D.810 of this preamble.

6. Recordation of ERC Generation and ERC Issuance

The EPA proposes to issue ERCs for ERC generating entities 

once per year. Thus, in a three3-year compliance period, for 

instance, there would be three points at which the agency issues 

ERCs. After each calendar year, the EPA will calculate the ERCs 

generated for EGU and non-EGU ERC generators based on data 

submitted to the EPA through the Emissions Collection and 

Monitoring Plan System (ECMPS). These calculated ERC quantities

will be proposed as part of a Notice of Data Availability (NODA) 

 

71 Note that these values will be the submitted values from the 

affected EGUs to the EPA that have gone through a transparent 

review process. 
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with a 30-day comment period. Subsequently, the EPA will 

finalize this NODA and issue ERCs accordingly with tracking and 

serial numbers. For affected EGUs with compliance accounts, the 

ERCs will be issued to these. For entities without compliance 

accounts, the EPA will issue ERCs to an entity’s general 

account. The timing for issuing ERCs is consistent with existing 

programs, and the EPA believes there is value in consistency. 

However, we solicit comment on the annual issuance of ERCs and 

whether issuance should occur at different intervals (e.g.,

quarterly, biannually, or other time frames). The EPA requests 

justification along with corresponding comments 

regardingERCregarding ERC-issuance intervals. We request comment 

on how reporting and recordkeeping requirements could be 

minimized, particularly for small entities, to the extent 

possible under the statute and existing regulations. 

a. Issuance of ERCs to Affected EGUs

Following the determination of the number of ERCs an 

affected EGU is eligible to receive, based on an affected EGU’s 

reported CO2 emission rate compared to a specified reference 

rate72, the EPA will issue those ERCs into the affected EGU’s 

compliance account in ATCS. The issuance will occur annually 

 

72 As described in section IV.C.1 of this preamble.
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through the NODA process. ERCs will have a unique serial number, 

tracking number, and will distinguish ERC type (i.e., if it is 

BB2 or not) when issued to an affected EGU.

b. Issuance of ERCs for Measures Used to Adjust an Emission Rate

In the final EGs, the EPA has specified requirements for an 

ERC issuance process for the quantification and verification of 

measures used to adjust an emission rate that provide the 

necessary rigor and transparency while being efficient and 

streamlined. This is the intent of the federal plan as well, 

where there is a particular concern with implementing a 

streamlined and efficient federal process for ERC issuance 

across federal plan states. As required in the final EGs, we are 

proposing a two-step application process to the federal plan 

tracking systems for ERCs that allows for project approval to 

take place prior to the performance period, and makes the 

issuance of ERCs as quick and efficient as possible after 

generation has been quantified and verified, while still 

assuring a rigorous approval process. For the first step in the 

ERC issuance application process, the EPA proposes that RE and 

nuclear generation providers submit to the EPA an eligibility 

application for EPA approval, or its designated agent, 

demonstrating that the project is eligible for the issuance of 

credits, including an EM&V plan that meets EPA requirements. The 
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EPA takes comment on all aspects of the proposed ERC issuance 

process. The EPA is also taking comment on how an ERC issuance 

process would apply to emission reduction measures for which we 

are taking comment regarding their eligibility for ERC issuance 

under the federal plan, including types of RE not covered by the 

federal plan, demand-side EE, CHP, biomass, and any other 

measure that could be considered eligible under the final 

guidelines.

The following are proposed required components of the 

eligibility application, as specified for these measures in the 

final emission guidelinesEGs:

(1) The EPA proposes that the federal plan will require 

that providers must show that the generation they would 

be providing to the federal plan system for ERC issuance 

is only being credited in the federal plan, and will not 

be submitted for ERC issuance in any other rate-based 

crediting system in any other state. As discussed in 

section IV.C. above, it is proposedof this preamble, we 

are proposing that states with rate-based emission 

standards plans that have eligibility and EM&V 

requirements compatible with the federal plan willwould

have the opportunity to participate in the federal plan 

trading systems, and create a shared pool of creditable 
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reductions, in which case credits approved by such states 

would be eligible for use by affected EGUs in the federal 

plan.

(2) The provider must show that the project is using an 

eligible RE or nuclear resource. Specific requirements 

are proposed in section IV.C of this rulepreamble.

(3) The provider must show that the project has an EM&V 

plan that meets the federal plan requirements. Proposed 

requirements specific to the federal plan are proposed in 

Sec.section IV.D.6 of this rulepreamble. As specified in 

Sec.section IV.D.8 of this preamble, we takerequest

comment on whether nuclear energy resources should be 

subject to the same EM&V requirements as renewable 

energyRE resources, and if not, we take comment on to 

which EM&V requirements nuclear energy resources should 

be subject.

(4) There are special conditions if the provider is 

located in a state with a mass-based plan. For eligible 

RE capacity, the provider can only be credited in a ratebased state or rate-based multi-state system if the 

provider can demonstrate that the measure must be 

implemented to meet electricity load in a state with a 

rate-based plan. The EPA is proposing that an RE provider 
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can make this demonstration by providing documentation of 

a power purchase agreement (PPA) or delivery contract 

from the rate-based state and show that the measure was

treated as a generation resource used to serve regional load 

that included the rate-based state. For incremental nuclear 

capacity, no provider in a state with a mass-based plan 

can be eligible for ERC issuance in a rate-based state.

This requirement and the justification for its inclusion 

is further discussed in Sec.section III.A. of this 

preamble on Interstate Effects and also discussed in the 

Interstate Effects section of the final guidelines 

(Sec.EGs (section VIII.L of the final EGs). The EPA is 

proposing that there is no other geographic limitation on 

the location of the providers of RE and incremental 

nuclear generation under the federal plan. 

(5) This application must include an independent thirdparty verifier’s review and approval of the eligibility 

requirements, as is reflected in EM&V requirements for 

the final guidelines, and specified as part of proposed 

federal plan EM&V requirements in Sec.section IV.D.6 of 

this rulepreamble. 

We request comment on each criterion of the eligibility 

application described herein and in the proposed model rule, 
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for each eligible resource. Specifically, we seek comment on 

the substantive content of the criteria, and we seek comment 

on the level of detail provided and whether more or less 

detail (and what detail) should be included in the final model 

rule.

ERCs will be tracked in the Allowance Tracking and 

Compliance System (ATCS). Additionally, the EPA is proposing 

that the agency will establish a complementary tracking system 

for the ERC issuance process. It will provide for transparent 

access to RE project and program eligibility applications and 

regulatory approvals as well as information on the activities 

of accredited third party verifiers (third party verifiers are 

further discussed in Sec.section IV.D.6 of this rulepreamble), 

as well for the public to be able to generate reports based on 

this information.

The agency is proposing that the project eligibility

applications will be accepted after the finalization of the 

federal plan and prior to the first compliance period, as soon 

as the agency is able to establish an application process, and 

that applications will be accepted on an annual basis. The 

agency requests comment on whether a quarterly or biannual 

application process is more appropriate. These applications 

will be accepted through the entirety of all compliance 
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periods. The EPA will review and approve the project 

applications. It is proposed that the EPA may designate an 

agent to coordinate the project application process and assist 

with review of applications.

For the second step in the credit issuance application 

process, the EPA proposes that providers submit an M&V report

to the EPA, or its designated agent, prior to the EPA’s 

issuance of ERCs. This can only occur after the approval of a 

project application, the RE has been generated, and necessary 

EM&V has been completed.

The following are proposed required components of the ERC

issuance application:

(1) Documentation of completed EM&V in accordance with the 

EM&V plan submitted by the RE provider, including 

quantification of the MWh of generation to be credited 

and verification of their creation.

(2) Documentation that the generation has not been 

submitted for crediting under any other federal or state 

plan, including to another rate-based credit tracking 

system.

(3) Documentation that the MWh resulted from RE or 

incremental nuclear capacity eligible for crediting under 

the federal plan requirements and in accordance with 
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final emission guidelines.EGs. This documentation should 

note if the MWh are from an RE project located in a state 

with a mass-based plan, and show if the generation is

approved to be eligible for ERC issuance under the 

federal plan. See section &&&IV.C.3 of this preamble for 

specifics on the required demonstration for this type of 

RE generation. As discussed in that section, this option 

is proposed to not be available to incremental nuclear 

capacity located in a state with a mass-based plan.

(4) This application must include a verification report 

from an independent third-party verifier, submitted after 

the verifier’s review and approval of the eligibility

application, as is reflected in EM&V requirements for the 

final guidelines, and specified as part of proposed 

federal plan EM&V requirements described below and 

included in detail in the proposed model rule.

If the application meets these requirements, pursuant to 

review by the EPA or its designated agent, ERCs will be issued 

to the provider by the EPA through the Allowance Tracking and 

Compliance System (ATCS). The specific steps of the process by 

which an eligible resource seeks ERCs, and by which an 

affected EGU may use ERCs in its compliance demonstration are 

laid out in the proposed model rule. One of the steps requires 
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the proponent to register for a general account in the EPA 

tracking system where the ERCs would be recorded. See 

section40 CFR 62.16515 for the requirements to establish a 

general account. While EPA is proposing to allow eligible 

resources to use a general account to receive any ERCs issued 

under this section, the EPA requests comment on extending the 

designated representative provisions in section40 CFR 62.16485 

to eligible resources instead of the general account 

provisions. Requiring eligible resources to submit information 

similar to that collected in the certificate of representation 

in section40 CFR 62.16500 and to appoint a designated 

representative to act on behalf of all owners/operators for 

all projects requesting ERCs may improve the EM&V process by 

making the eligible resources more accountable.

Because it is critical to the integrity of an ERC that it 

represents the actual MWh of energy generated or saved that it 

purports to represent, and as required in the emission 

guidelinesEGs for state plans, the federal plan and model rule 

include provisions to address error correction (mechanisms to 

adjust the number of ERCs issued based on all form of errors, 

from clerical, to over- and under-statements, to material 

inconsistency with rule provisions, to fraud, etc.). In 

addition, the federal plan and model rule include provisions 
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that provide that, at any time for cause, the EPA may 

temporarily or permanently revoke the qualification status of 

eligible resources (from being issued ERCs for at least the 

duration it does not meet the requirements for being issued 

ERCs) and independent verifiers (from providing verification 

services for at least the duration it does not meet the 

requirements of your state plan). For the federal plan, as 

discussed in section III.I of this preamble above, we propose 

to use the administrative appeals process set forth 40 

C.F.R.CFR part 78 to address party-specific disputes 

concerning the issuance and/or validity of ERCs. States may 

adopt a similar procedural and substantive process at the 

state level to enable them to rescind or withhold approval of 

specific credits. We request comment on the content of each of 

these provisions in the model rule, and specifically seek 

comment on whether the model rule should include different or 

additional details related to either procedure or substance 

for error correction and the revocation of the qualification 

status of an eligible resource or independent verifier.

The agency is proposing that ERC eligibility applications 

will be accepted starting before the beginning of the first 

compliance period (January 1, 2022), through an application 

process the agency will establish and administer (unless 
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delegated or taken over through a partial state plan), and 

that applications will be accepted on an annual basis. These 

applications will be accepted through the entirety of all 

compliance periods. The EPA will review and approve 

eligibility applications, and may designate an agent to 

coordinate and assist with ERC eligibility applications. The 

EPA is proposing that it will issue ERCs for a given year no 

later than 6 months after the end of the relevant year. This 

amount of time may be necessary to accommodate the ERC 

issuance process, including necessary EM&V... The overall 

proposed schedule for trading and true-up has been constructed 

to allow for this period of time for EM&V after the compliance

period.

&&&Placeholder for language on provisions to encourage 

early action that is being worked on offline&&& 

For purposes of the proposed rate-based federal plan, the EPA 

proposes to implement the Clean Energy Incentive Program (CEIP) by 

issuing early action ERCs for eligible actions located in or 

benefitting a state that are implemented after September 6, 2018 

and that generate zero-emitting MWh or reduce energy demand in

2020 and/or 2021. The EPA intends to implement the program in a 

way that maintains the stringency of the rate-based emission 

standards for affected EGUs in the compliance periods established 
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in this rule. For the purposes of the rate-based federal plan, the 

EPA is proposing to award early action ERCs to two types of 

eligible projects, as listed below. The rationale for including 

these projects is included in section VIII.B.2 of the final EGs.

• RE investments that generate metered MWh from any type of 

wind or solar resources; and

• Demand-side EE programs and measures implemented in lowincome communities that result in quantified and verified 

electricity savings (MWh).

The EPA proposes the following framework to implement the CEIP 

in the rate-based federal plan. First, the EPA proposes to 

implement a mechanism for issuing early action ERCs for eligible 

actions implemented after September 6, 2018 and that generate zeroemitting MWh or reduce end-use energy demand during 2020 and/or

2021. The EPA proposes to design this mechanism in a manner that 

would have no impact on the aggregate emission performance of 

sources required to meet rate-based emission standards during the 

compliance periods. The EPA requests comment on the structure of 

this mechanism, which could include adjusting the stringency of 

the emission standards during the compliance periods to account 

for the issuance of early action ERCs for MWh generated or avoided 

in 2020 and/or 2021. For example, during the interim performance 

period, a number of ERCs could be retired in an amount equivalent 
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to the number of early action ERCs that were awarded for MWh 

generated or avoided in 2020 and/or 2021. As another option, the 

EPA, or a state under the model trading rule, could adjust their 

targets to achieve the same stringency, taking into account the 

additional borrowed ERCs. The EPA requests comments on all 

potential methods to adjust state targets, including modelingbased approaches, and on what information the state must present 

to demonstrate that the new targets preserve the needed stringency. 

More generally, the EPA requests comments on these ideas, as well 

as on alternatives for maintaining the stringency of a rate-based 

plan implementing the CEIP so as to have no impact on the aggregate 

emission performance of sources required to meet rate-based 

emission standards during the compliance periods.

Second, the agency proposes to create an account of “matching” 

ERCs for each state participating in the CEIP – regardless of 

whether a state is implementing a state plan or the agency is 

implementing a federal plan on its behalf. This distribution would 

reflect each state’s pro rata share – based on the amount of the 

reductions from 2012 levels the affected EGUs in the state are 

required to achieve relative to those in the other participating 

states – of a federal pool of additional ERCs, which would be 

limited to the equivalent of 300 million short tons of CO2

emissions. Thus, states whose EGUs have greater reduction 
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obligations will be eligible to secure a larger proportion of the 

federal pool upon demonstration of quantified and verified MWh of 

RE generation or demand side-EE savings from eligible projects 

realized in 2020 and/or 2021. The EPA intends that a portion of 

these matching ERCs would be reserved for eligible wind and solar 

projects, and a portion would be reserved for eligible EE projects 

implemented in low-income communities. The agency recognizes that 

there have been historic economic, logistical and information 

barriers to implementing EE programs in these communities, and 

therefore believes it is appropriate to reserve a portion of the 

federal pool to incentivize investment in these programs. The EPA 

is requesting comment on the size of reserve of matching ERCs for 

eligible low-income EE programs as well as for eligible wind and 

solar projects. The EPA is proposing that unused ERCs in either 

reserve would redistributed among participating states. This 

redistribution could be executed according to the pro-rata method 

discussed above. Alternatively, unused matching EE or RE ERCs could 

be swept back into a federal pool and distributed to project 

providers on a first-come, first served basis. EPA requests comment 

on these ideas as well as alternative proposals regarding the 

method for redistributing matching ERCs, as well as the appropriate 

timing for such a redistribution.

Following the effective date of a rate-based federal plan for 
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a state, the agency will create an account of matching ERCs for 

the state that reflects the pro rata share of the 300 million short 

ton CO2 emissions-equivalent matching pool that the state is 

eligible to receive. Any matching ERCs that remain undistributed 

after September 6, 201873 will be distributed to those states with 

approved state plans that include requirements for CEIP 

participation, as well as to those states on whose behalf EPA is 

implementing a federal plan. These ERCs will be distributed 

according to the pro rata method outlined above. Unused matching 

ERCs that remain in the accounts of states participating in the 

CEIP on January 1, 2023, will be retired by the EPA.

The EPA requests comment on how the 300 million short ton CO2

emissions-equivalent pool may be converted into ERCs for the 

purpose of populating the CEIP accounts of states with rate-based 

plans. 

Third, the EPA is proposing to award early action ERCs and 

matching ERCs to eligible projects as follows, based upon the 

quantified and verified MWh of generation or savings achieved by 

the projects in 2020 and/or 2021:

 

73 This may occur because not all states may elect to include 

requirements for CEIP participation in their state plans. 
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• For RE projects that generate metered MWh from any type of 

wind or solar resources: for every two MWh generated, the 

project will receive one early action ERC and one matching 

ERC from the EPA.

• For EE projects implemented in low-income communities: for 

every two MWh in end-use demand savings achieved, the 

project will receive two early action ERCs and two matching 

ERCs from the EPA. 

The EPA will address implementation details of the CEIP in a 

subsequent action. ERCs awarded by the EPA pursuant to the CEIP 

may be used for compliance by an affected EGU with its emission 

standards in any compliance period and are fully transferrable 

prior to such use. 

The EPA requests comment on all aspects of implementing the 

CEIP under a rate-based federal plan approach, including (1) The 

method for maintaining the stringency of rate-based emission 

standards; (2) the criteria for eligible projects, including 

criteria for awards to EE projects that benefit low-income 

communities; (3) the mechanism for reviewing project submittals 

and issuing early action ERCs; (4) EM&V requirements for eligible 

projects; (5) M&V reports; (6) verification reports from an

independent verifier; and (7) the number of early action and 

matching ERCs that should be awarded for each MWh of generation or 
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savings from eligible projects to ensure a robust market response 

to the program. The EPA also seeks comment on how states, tribes 

and territories for whom goals have not yet been established in 

the final EGs may be able to participate in the CEIP in the future.

7. Independent Verifiers

The EPA has determined in the final EGs that independent 

verification requirements are necessary to ensure the integrity 

of any rate-based emission trading program, given the types of 

eligible measures that may generate ERCs and the broad 

geographic locations in which those measures may occur. 

Inclusion of an independent verification component provides 

technical support for the EPA in the context of the proposed 

federal plan, and the states in the context of their plans, to 

ensure that eligibility applications and monitoring and 

verification reports are appropriately reviewed prior to 

issuance of ERCs. Inclusion of an independent verification 

component is also consistent with similar approaches required by 

state PUCs for the review of demand-side EE program results and 

GHG offset provisions included in state GHG emission budget 

trading programs.

The remainder of this section and the related language in 

the proposed model rule provide the proposed basis by which the 

EPA intends to evaluate the independence of the verifiers that 
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it uses to provide verification reports pursuant to the federal 

plan. The qualifications described here and in the model rule 

would be presumptively approveable in the context of a state 

plan.

As a starting point, an independent verifier must have the 

necessary technical qualifications to provide verification 

services for the subject in question, as well as fulfill certain 

codes of conduct in providing verification services. Only 

verifiers approved or “accredited” by the EPA may provide 

verification services related to ERC issuance for the federal 

plan, in the same way that only verifiers approved by a state 

may be eligible to perform verification services pursuant to a 

state plan.74

In addition, verifiers must have sufficient knowledge of 

the rate-based emission trading program rules, technical 

expertise, and knowledge of auditing, accounting, and 

information management practices, in order to perform 

verifcation services related to the Clean Power Plan. Accredited 

verifiers must be independent. Accredited verifiers may not 

 

74 In this section, the term “verifier” is used interchangeably to 

refer to both a “verification body” (i.e., a verification company 

or organization) and a “verifier,” which is an individual that is 

a principal or employee of a verification body.
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provide verification services for any eligible resource for 

which they have a financial, management, or other interest.75

Such relationships constitute a conflict of interest (COI). COI 

 

75 Accredited verification bodies and individual verifiers may 

not have any direct or indirect organizational or personal 

relationships with an ERC provider that would impact their 

impartiality in assessing the validity and accuracy of the 

information in an eligibility application or M&V report. In 

addition to this general requirement, the following specific 

requirements also apply. Accredited verifiers must have no 

direct or indirect financial interest in, or other financial 

relationships with, an ERC provider or any related program or 

project that seeks issuance of ERCs. Accredited verifiers must 

have no relationship with the implementer of a program or 

project that seeks the issuance of ERCs, or any related ERC 

provider, that would represent a COI. Accredited verifiers must 

have no role in the development and implementation of a program 

or project that seeks issuance of ERCs, beyond the provision of 

verification services. Accredited verifiers must not be 

compensated, directly or indirectly, in relation to the 

quantified and verified MWh in an M&V report or on the basis of 

program or project approval, ERC issuance, or the number of ERCs 

issued. Accredited verifiers may not hold ERCs, or other 

financial derivatives related to ERCs, or have a financial 

relationship with other parties that hold ERCs or other related 

financial derivatives. Verification reports must include an 

attestation by the accredited verifier that it assessed 

potential COI related to an ERC provider and adequately 

addressed any identified COI. The EPA requests comment the 

potential for payments to be channeled through the EPA as fees. 
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situations may also arise as a result of personal relationships 

among individuals representing an ERC provider and an accredited 

verifier. A verification report will not be accepted as part of 

an eligibility application or M&V report where the accredited 

verification body or any individual verifier has a COI. 

Accredited verification bodies must have management protocols in 

place to identify and remedy any COI prior to provision of 

verification services. That the proposed federal plan and model 

rule provide that failure of an accredited verifier to identify 

and adequately address any COI prior to provision of 

verification services is grounds for revocation of 

accreditation. The EPA will perform periodic reviews of 

accredited verifiers, to ensure that verifiers are maintaining 

necessary technical and professional qualifications and are 

meeting program requirements for provision of verification 

services. The EPA may recognize, in part, accreditation by an 

outside organization where such outside accreditation 

demonstrates that federal plan requirements are met.76 The EPA 

requests comment on the proposed necessary requirements for an 

 

76 An example is American National Standards Institute (ANSI) 

accreditation under ISO 14065:2013 for GHG validation and 

verification bodies. More information is available at 

https://www.ansica.org/wwwversion2/outside/GHGgeneral.asp.
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independent verifier to perform verification services in

connection with the federal plan, including those requirements

specifically detailed in this section of the preamble and the 

related language in the proposed model rule, and including 

whether there are any requirements that are not included in this 

proposal that should be included in the final rule. We further 

request comment on the level of detail that we should include in 

the final model rule regarding all requirements for indepenent 

verifiers, and all aspects of verification.

8. Evaluation, Measurement, and Verification (EM&V) Plans, 

Monitoring and Verification (M&V) Reports, and Verification 

Reports

This section identifies and discusses the EM&V approaches

used to quantify and verify MWh from RE, demand-side EE, and 

other eligible measures used to generate ERCs or otherwise 

adjust an emission rate.77

Only a subset of the potentially creditable ERC resources 

 

77 EM&V is defined here as the set of procedures, methods, and 

analytic approaches used to quantify the MWh from RE, demand-side 

EE, and other eligible measures and thereby ensure that the 

resulting savings and generation are quantifiable and verifiable. 

In this proposal, we are proposing EM&V for the eligible RE, and 

taking comment on EM&V for demand-side EE and any other measures 

that could be eligible. 
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discussed in this section are actually being proposed as part of 

the federal plan. The remainder, and their associated 

requirements, are provided as part of the proposed model trading 

rule. Thus, all provisions of this subsection relating to such 

resources are presented only for the purpose of comment in the 

context of the federal plan, but are actually proposed for 

inclusion in the model trading rule. The ERC resources proposed 

in the federal plan must meet the following criteria: 1) they 

are in the following categories of measures: on-shore wind, 

solar photovoltaics (PV), concentrated solar power, geothermal 

power, hydropower, new nuclear units and capacity uprates at 

existing nuclear units, and 2) they can provide quantified 

generation data from a revenue quality meter. The language 

pertaining to all other measures (e.g., demand-side EE) is 

proposed only for the model rule. While they are currently being 

proposed as part of the model rule and not the federal plan, the 

EPA requests comment on the inclusion of other RE measures,

demand-side EE measures, and any other measures that may be 

eligible under the final guidelines as eligible measures under 

the federal plan. For stakeholders that are submitting comments 

on the inclusion of such additional measures, the EPA requests 

comment on how the EPA could implement across applicable 

jurisdictions a rigorous, straightforward, and widely 
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demonstrated set of EM&V methods, procedures, and approaches

that could be implemented in the time frame allowed by the 

federal plan and that also meet the requirements outlined in the 

final guidelines. To the extent proposed for inclusion in the 

model trading rule, we also invite comment on these requirements 

in the context of state implementation as part of a state plan. 

Thus, commenters on this aspect of the proposal should consider 

whether and how these provisions could be implemented at the 

state level. Comments that suggest an approach not authorized by 

the EGs will likely be considered out ofoutside the scope of 

this actionproposed rule.

Additionally, with respect to EM&V, the EPA describes 

certain established industry best-practice methods, procedures, 

and appraoches that would be presumptively approvable if 

included in state plans. States wishing to adopt the model rule 

must submit these methods, procedures, and approaches as 

specified, or may submit alternative EM&V that is functionally 

equivalent to the industry best-practices described as 

presumptively approvable.78

 

78 The EPA recognizes that EM&V is routinely evolving to reflect 

changes in markets, technologies and data availability, and 

expects to update its EM&V guidance over time. Therefore the agency 

expects that alternative quantification approaches will emerge 
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As discussed in section IV.C.3 of this preamble, quantified 

and verified MWh of RE generation and other means of generating 

ERCs may be used to adjust a CO2 emission rate when demonstrating 

compliance with the emission guidelinesEGs. Providers other than 

affected EGUs who seek to earn ERCs must develop EM&V plans 

outlining how they will quantify and verify the resulting MWh 

from their efforts. These providers must then submit these EM&V 

plans as part of their application to the Administrator for 

project approval.79

a. Overall Approach and Measure-Specific Requirements

The proposed CPP EGsClean Power Plan stated that the EPA 

would establish EM&V requirements and procedures to help states, 

sources, and resource providers quantify and verify MWh savings 

and generation resulting from zero-emitting RE and demand-side 

EE efforts. This federal plan proposes those requirements that 

the EPA committed to establish. The CPP EGsClean Power Plan

proposal and associated “State Plans Considerations” TSD80

 

that can be approved for use, provided that such approaches are 

functionally equivalent to the provisions for EM&V outlined in 

this section. 

79 A full discussion of applicable requirements for the 

establishment and functioning of the rate-based trading system is 

provided above, in section IV.D of this preamble.

80 See discussion beginning on p. 34 of the State Plan 
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suggested that such EM&V requirements would leverage existing 

industry practices, protocols, and tracking mechanisms currently 

utilized by the majority of states implementing RE and demandside EE. The EPA further noted that many state regulatory bodies 

and other entities already have significant EM&V infrastructure 

in place and have been applying, refining, and enhancing their 

evaluation and quality assurance approaches for over 30 years, 

particularly with regard to the quantification and verification 

of energy savings resulting from utility-administered EE 

programs. The EPA also observed that the majority of RE 

generation is typically quantified and verified using readily 

available, reliable, and transparent methods such as direct 

metering of MWh. The EPA is proposing EM&V methods, procedures, 

and approaches, described herein, that are intended to be 

consistent with and leverage prevailing industry best-practices.

In addition, the EPA’s proposed EM&V methods, procedures, 

and approaches reflect several overarching objectives and 

principles offered by states, private organizations, and the 

public during the comment period of the CPP EGs. One of these is 

the importance of balancing the accuracy and reliability of 

 

Considerations TSD for the Clean Power Plan Proposed Rule: 

http://www2.epa.gov/carbon-pollution-standards/clean-power-planproposed-rule-state-plan-considerations.
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results with the associated costs of EM&V. Another objective for 

the EPA’s proposed EM&V is to avoid excessive interference with 

existing practices that are already robust, transparent and 

effective. 

(1) Submittals.

Applicable submittals under a rate-based emission trading 

program include eligibility applications (including EM&V plans),

monitoring and verification reports, and verfication reports. 

These submittals are described in section &&& VIII.K.23.b of the 

CPPfinal EGs preamble and in this model rule and federal plan. 

At the initiation of a program or project, ERC providers develop 

and submit to the state or the EPA, respectively, an EM&V plan 

that documents how requirements for quantification and 

verification will be addressed as EM&V is performed over the 

program or project period. After implementation has occurred, 

the ERC provider must submit periodic monitoring and 

verification (M&V) reports to document and describe how each of 

the requirements were applied. These reports must also specify 

the resulting MWh savings or generation values, as determined on 

a retrospective (ex-post) or real-time basis. MWh values may not 

be determined using projections or other ex-ante quantification 

approaches. 

Each EM&V plan submitted in support of an eligibility 
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application must identify the eligible resource covered by the 

plan, and provide specific EM&V criteria that specify the manner 

in which the energy generated or saved by the eligible resource 

will be quantified, monitored and verified. The manner of 

quantification, monitoring and verification must meet the 

criteria outlined below and included in the proposed model rule, 

as applicable to the specific eligible resource. We take broad 

comment on each criteria specified below and in the proposed 

model rule, for each eligible resource. Specifically, we seek 

comment on the substantive content of the criteria, and we seek 

comment on the level of detail provided and whether more or less 

detail (and what detail) should be included in the final model 

rule, and whether the criteria should differ for each eligible 

resource.

Each M&V report submitted in support of the issuance of 

ERCs to a specific eligible resource must include specific 

criteria described here and in the proposed model rule. For the 

first M&V report submitted, a key component is documentation 

that the electricity-generating resources or electricity-saving 

measures were installed or implemented consistent with the 

description in the approved eligibility application. Each 

following M&V report must then identify the time period covered 

by the M&V report, describe how the methods specified in the 
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EM&V plan were applied during the reporting period, and document 

the quantify (in MWh) of energy generation and/or electricity 

savings quantified and verified for the period covered by the 

M&V report. Any change in the energy generation or savings 

capability of the eligible resource during the period covered by 

the M&V report must also be included in the M&V report, along 

with the date on which the change occurred, and information 

sufficient to demonstrate whether the eligible resource 

continued to meet all eligibility requirements during the period 

covered by the M&V report. Any change should also be specified 

in the report. The EPA takes broad comment on each of these 

criteria, as described here and in the proposed model rule. 

Specifically, we seek comment on the substantive content of the 

criteria, and we seek comment on the level detail provided and 

whether more or less detail (and what detail) should be included 

in the final model rule, and whether the criteria should differ 

for each eligible resource.

Each verification report submitted by an independent 

verifier in support of the issuance of ERCs to a specific 

eligible resource must address the criteria described here and 

in the proposed rule text. Each verification report must set 

forth the findings of the verifier, based on an assessment of 

all relevant requirements, information and data, including an 
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assessment of any material misstatements or data discrepancies. 

Any verification report included as part of an eligibility 

application must further describe the review conducted by the 

verifier and verify the following: the eligibility of the 

resource to be issued ERCs; that the eligible resource exists 

and has been, or will be, generating energy or saving 

electricity in the manner required; that the EM&V plan meets its 

requirements; and any other information required or that the 

verifier finds, in its professional opinion, is necessary to 

assess the accuracy of the subject of the verification report. 

Each verification report included as part of a M&V report must 

also describe the review conducted by the verifier and verify

the following: the adequacy and validity of the information and 

data submitted to quantify eligible MWh of electric generation 

or electricity savings during the period covered by the report, 

as well as all supporting information and data identified in the 

EM&V plan and M&V report; evaluate whether all generation or 

savings data is within a technically feasible range for that 

specific eligible resource (determined through a quality 

assurance and quality control check of the data); that the M&V 

report meets its requirements; and any other information 

required or that the verifier finds, in its professional 

opinion, is necessary to assess the accuracy of the subject of 
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the verification report. The EPA takes broad comment on each of 

these criteria, as described here and in the proposed model 

rule. Specifically, we seek comment on the substantive content 

of the criteria, and we seek comment on the level of detail 

provided and whether more or less detail (and what detail) 

should be included in the final model rule, and whether the 

criteria should differ for each eligible resource.

For demand-side EE, all EM&V plans that are developed for 

purposes of adjusting an emission rate under this final rule are 

intended to leverage and closely resemble the plans already in 

routine use for a wide range of publicly or rate-payer funded EE 

programs and energy service company (ESCO) projects. For RE, 

EM&V plans similarly leverage resources and approaches to MWh 

tracking for RE that are broadly applied in the state and 

regions. The existing reports and documentation from existing 

tracking systems may serve as the substantive basis for a 

monitoring and verification report for RE.

b. Renewable Energy EM&V Requirements

This section describes the EM&V requirements associated 

with quantifying electricity generation from eligible RE and 

nuclear, and for documenting these requirements in EM&V plans 

and reports. Consistent with prevailing views expressed in 

public comments, the EPA’s requirements presume that the 
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quantification of RE generation can leverage the infrastructure 

and documentation associated with the establishment of renewable 

energy certificatecertificates (RECs) and registration of such 

certificates in REC registries. These registries typically 

include well-established safeguards, documentation requirements, 

and procedures for registry operations intended to support the 

demonstration of compliance with state RPS policies. A key 

element of RPS compliance is that each RE generating unit must 

be uniquely identified and recorded in a registry to avoid the 

double counting of RECs.

The primary metric for all RE is electricity generation, in 

units of MWh. Measured output must be derived either from (1) A

revenue quality meter that meets the applicable ANSI C-12 

standard or equivalent, which is the typical requirement for 

settlements with RTO and other control-area operators; or (2) 

for customer-sited generators that are interconnected behind the 

customer meter, measurement at the AC output of an inverter, 

adjusted to reflect the energy delivered into either the 

transmission or distribution grid at the generator bus bar.

Further, a RE generating facility of 10 kWKilowatt capacity or 

less may estimate the facility’s output if the state where it is 

located explicitly allows estimates to be used and provides 

rules for when it will be allowed. In the latter case, 
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calculations of system output must be based on the RE unit’s 

capacity, estimated capacity factors, and an assessment of the 

local conditions that affect generation levels. All such input 

parameters and assumptions must be clearly described and 

documented. For RE units that are managed by regional 

transmission operators or other control area operators, metered 

generation data should be electronically collected by the 

control area’s energy management system, verified through an 

energy accounting or settlements process, and reported by the 

control area operator to the REC registry at least monthly. The 

EPA requests comment on this proposed requirement for 

quantifying RE generation for the purpose of ERC issuance.

For RE units that do not go through a control area 

settlements process, metered data may be read and transmitted to 

the ERC registry by an independent third party, or may be selfreported. Third-party and self-reported generation data must be 

reported on an annual basis. All such data must be verified for 

reasonableness by the agency, state or the REC registry. 

For reporting purposes, RE generation may be aggregated 

from multiple generators into a single MWh value for the group, 

provided the following requirements are met: each RE unit is 

uniquely identified in the federal tracking system, the 

nameplate capacity of each RE unit is less than 150 kWKilowatt, 
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the aggregated RE units collectively have nameplate generating 

capacities less than 1.0 MW, the units aggregated are located in 

the same state, the RE units being aggregated utilize the same 

technology/fuel type, and the RE unit’s generation data are 

based on the same metering or the same generation estimating 

software or algorithms. The EPA requests comment on how existing 

reporting systems can play a role in meeting EM&V requirements 

under the federal plan, particularly, in assuring that each MWh 

of RE generation is uniquely identified and recorded to avoid

double counting.

An additional criterion that applies to distributed RE 

units that directly serve on-site end-use electricity loads is 

that avoided transmission and distribution (T&D) system losses 

can be considered, as is commonly practiced with demand-side EE. 

Such calculations must apply the requirements specified for 

demand-side EE as described below. 

The EPA requests comment on all metering, measurement, 

verification, and other requirements included in this 

subsection, includuing the appropriateness of their use for each 

type of renewable energyRE resource (including the relvant size 

and distribution of such resource) that qualifies for issuance 

of ERCs for use in Clean Power Plan compliance.

For renewable energyRE resources with a nameplate capacity 
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of 10 kWKilowatt or more and for renewable energyRE resources

with a nameplate capacity of less than 10 kWKilowatt for which 

metered data are available, we take comment on the 

appropriateness of the requirement to use a revenue quality 

meter for monitoring generation, and we take comment on the 

definition of revenue quality meter. We take comment on the 

appropriateness of other types of meters for monitoring 

generation. We take comment on whether 10kW10 Kilowatt is the 

appropriate threshold, under which an eligible resource can be 

issued ERCs for generation based on data other than metered 

generation, and if not, what would be the appropriate threshold. 

For renewable energyRE resources of all sizes and means of 

monitoring, we take comment on the appropriate requirements for 

allowing generation data to be aggregated, including comment on 

the provisions in the proposed model rule and any alternatives 

to them. We take comment on whether the all of the generating 

units have the same essential generation characteristics, in 

order for their data to be aggregated, and if so, what the 

appropriate content of the definition of “essential generation 

characteristics” (e.g., are essential generating characteristics 

determined on a resource by resource basis, or can generation 

from a group of wind turbines be aggregated with generation from 

a group of solar panels? We seek comment on the appropriate 
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thresholds for the aggregated of individual units (e.g., 

nameplate capacity of less than 150 kWKilowatt per unit and the

units collectively do not exceed a total nameplate capacity of 1 

MW when aggregated, as in the proposed model rule).

For non-metered units of less than 10 kWKilowatt, we take 

comment on whether the final model rule should specify the 

specific estimating software or algorithms by which generation 

data should be measured, and if so, we take broad comment on the 

appropriate estimating software or algorithms and/or the 

appropriate characteristics for such estimating software or 

algorithms.

We request comment on any other requirements that should be 

included in the final model rule regarding EM&V of renewable 

energyRE resources.

For all energy generating resources (such as RE, but also 

including applicable resources requiring EM&V described below), 

we take comment on the appropriate place of measurement of the 

generation, including comment on whether measurement should be 

at the bus bar or at a different location (or in the case of 

meter on units of less than 10kW10 Kilowatt, at the AC output of 

the inverter or elsewhere), whether measurement should be before 

or after parasitic load (and how to separate out parasitic 

load). In addition, for all energy generating resources, we take 
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comment on whether generation data should go through a control 

area settlement process prior to issuance of ERCs, and if so, 

what level of specificity with respect to that process we should 

include in the final model rule. If not, or if the unit does not 

go through a control areas settlement process, we take comment 

on how the data collection should be specified in the final 

model rule. Finally, we take comment on the frequency with which 

data should be collected, for all energy generating resources, 

of all sizes.

c. Nuclear EM&V Requirements

The EM&V requirements associated with quantifying 

electricity generation from eligible nuclear, and for 

documenting these requirements in EM&V plans and reports are the 

same as the requirements for RE discussed in the preceding 

section. 

The EPA requests comment on all metering, measurement, 

verification, and other requirements included in this 

subsection, includuing the appropriateness of their use for each 

type of renewablenuclear energy resource (including the relvant 

size and distribution of such resource) that qualifies for 

issuance of ERCs for use in Clean Power Plan compliance. We take 

comment on whether nuclear energy resources should be subject to 

the same EM&V requirements as renewable energyRE resources, and 
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if not, we take comment on to which EM&V requirements nuclear 

energy resources should be subject.

d. Non-Affected Combined Heat and Power EM&V Requirements

In additon to the CHP specific EM&V requirements discussed 

below and in the associated provisions in the model rule, all

CHP must follow the requirements for RE discussed in the 

preceding section, including metering requirements, special 

treatment for units of less than 10 kwKilowatt, and how to 

account for T&D losses. 

To calculate a CHP unit’s creditable MWh, the electrical 

output is prorated based on the “incremental CO2 emission rate” 

of the CHP unit relative to the applicable CO2 emission rate for 

affected EGUs in the state. The CHP unit’s electrical output 

would be prorated based on the CO2 emission rate of the 

electrical output associated with the CHP unit.81 The incremental 

rate would be relative to the applicable CO2 emission rate for 

affected EGUs in the state and would be limited to values 

 

81 The applicable CO2 emission limit rate depends on the type of 

state plan being implemented. Where a state plan includes a single 

CO2 emission limit rate for the fleet of affected EGUs, the 

applicable rate is the rate that applies to all affected EGUs. 

Where a state plan includes subcategorized rates for different 

categories of affected EGUs, the applicable rate is the rate that 

applies to affected NGCC EGUs. 
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between 0 and 1.

Prorated MWh = (1 - incremental CHP emission 

rate/applicable affected EGU emission limit rate) * CHP MWh 

output, where the ratio is limited to values between 0 and 1.

The CHP electrical emission rate is the net emission rate 

when the CHP unit’s thermal output emissions are deducted from

the CHP unit’s total emissions. It can be derived as follows

[CHP fuel input * fuel emission factor – (UTO/boiler 

efficiency) * fuel emission factor]/CHP MWh

In order to determine the incremental CO2 emission rate, a 

CHP unit would monitor requirements for CO2 emissions and energy 

output.82 The monitoring requirements are standard methods 

currently in use and the requirements would depend on the size 

of the CHP units and the fuel used in the unit.

Non-affected CHP facilities83 with electric generating 

capacity greater than 25 MW would follow the same monitoring and 

reporting protocols for CO2 emissions and energy output as are 

required for affected EGU CHP units. These requirements are 

discussed in section IV.D.13. of this preamble. For non-affected 

 

82 Where a CHP unit uses biomass fuel, it must report both total 

CO2 emissions and biogenic CO2 emissions. Proposed requirements for 

reporting biogenic CO2 emissions are discussed below in the section 

titled ‘EM&V requirements that apply to biomass RE facilities.’

83 A CHP facility may consist of one or more electric generators.
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CHP facilities with electric generating capacity less than or 

equal to 25 MW, which use only natural gas and/or distillate 

fuel oil, the low mass emission unit CO2 emission monitoring and 

reporting methodology outlined in 40 CFR 75 is acceptable. 

The EPA requests comment on all metering, measurement, 

verification, and other requirements included in this subsection 

with respect to CHP, including the appropriateness of their use 

for CHP (including with respect to the size of the CHP 

resource). We take comment on whether a CHP unit should be 

subject to the same EM&V requirements as renewable energyRE

resources, and we take comment on any additional EM&V 

requirements to which CHP units should be subject. Specifically, 

we take comment on specifying in the final model rule that if a

combined heat and powerCHP unit has an electric generating 

capacity greater than 25 MW, its EM&V plan must specify that it 

will meet the requirements that apply to an affected EGU under 

§40 CFR 62.16540 of this subpart.. We also take comment on 

specifying in the final model rule that if a combined heat and 

powerCHP unit has an electric generating capacity less than or 

equal to 25 MW, the EM&V plan must specify that it will meet the 

low mass emission unit CO2 emission monitoring and reporting 

methodology in 40 CFR 75. We take comment on any alternatives to 

these measurement methodologies that should be specified in the 
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final model rule. We take comment on any other requirements that 

should be included in the final model rule regarding EM&V of 

CHP.

e. Biomass EM&V Requirements

A state plan that is adopting the rate-based model rule

must propose EM&V requirements for monitoring and reporting 

biogenic CO2 emissions from the use of qualified biomass at RE 

facilities that are eligible for adjusting a CO2 emission rate. 

If a state proposes to use the monitoring and reporting 

requirements for biogenic CO2 emissions in 40 CFR part 98 (§§(40 

CFR 98.3(c), 98.36(b)-(d), 98.43(b), and 98.46) in its plan 

submission, those requirements are presumptively approvable. An 

EM&V plan that addresses biomass RE must follow the requirements 

for monitoring and reporting biogenic CO2 emissions from the 

facility that were approved by the EPA in connection with the 

specific state plan.

The EPA requests comment on all metering, measurement, 

verification, and other requirements included in this subsection 

with respect to biomass, including the appropriateness of their 

use for qualified biomass. We take broad comment on the types of 

qualifying biomass feedstocks that should be specified in the 

final model rule, if any. We take comment on the methods that we 

should specify in the final model rule for the measurement of 
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the associated biogenic CO2 for such feedstocks, as well as what 

other requirements we should specify in the final model rule 

related to qualfied biomass. We take comment on any other 

requirements that should be included in the final model rule 

regarding EM&V for qualifyingqualified biomass. Detailed 

discussion on the role of qualifyingqualified biomass feedstocks 

can be found in Sec.section IV.C.3. of this preamble.

f. Waste-to-Energy EM&V Requirements

A state plan that is adopting the rate-based model rule

must propose EM&V requirements for monitoring and reporting 

biogenic CO2 emissions from waste-to-energy facilities that are 

eligible for adjusting a CO2 emission rate. If a state proposes 

to include the monitoring and reporting requirements for 

biogenic CO2 emissions in 40 CFR part 98 (§§(40 CFR 98.3(c), 

98.36(b)-(d), 98.43(b), and 98.46) in its plan submission, those 

requirements are presumptively approvable. The EPA may approve 

other requirements of similar rigor, at its discretion. An EM&V 

plan that addresses the biogenic CO2 emissions from a waste-toenergy facility must follow the requirements for monitoring and 

reporting biogenic CO2 emissions from the facility that were 

approved by the EPA in connection with the specific state plan. 

As discussed in the final CPP EGs (see Sec.section VIII.K.1

of the final EGs), only the portion of electric generation at a 
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waste-to-energy facility that is due to the biogenic content of 

the MSW may be used to generate ERCs or counted by a state 

towards its achievement of its obligations pursuant to this 

regulation. 

The EPA requests comment on all metering, measurement, 

verification, and other requirements included in this subsection 

with respect to WTE, including the appropriateness of their use 

for WTE. We take comment on whether a waste-to-energy resource

should be subject to the same EM&V as renewable energyRE

resources, and we take comment on any additional EM&V 

requirements to which waste-to-energy resources should be 

subject, including comment on any specific methods for 

determining the specific portion of the total net energy output

from the resource that is related to the biogenic portion of the 

waste that the EPA should include in the final model rule.

g. Demand-Side Energy Efficiency EM&V Provisions

The following section describes proposes EM&V provisions

that will be presumptively approvable EM&V provisions that may

beif included in state regulations governing how EE is to be 

quantified by EE providers and is verified by independent 

entities acting on behalf of the state. TheseAs noted above 

these proposed provisions apply to all demand-side EE used to 

adjust an emission rate. if a state adopts the model rule. The 
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EPA is soliciting comment on the incorporation of EE for the 

federal plan and by extension the EM&V associated with it.

For all demand-side EE used to generate ERCs, the EPA is 

proposing that the metric is MWh of electricity savings, which 

is must be quantified on an ex-post or real-time basis and 

defined as a reduction in facility- or premises-level 

electricity consumption due to an EE program, project, or 

measuresmeasure. 

(1) Common Practice Baseline 

Based on public input and assessments of industry bestpractice protocols and procedures, the EPA has determinedis 

proposing that ait is presumptively approvable EM&V provision is 

quantifyingto quantify EE savingsavings as the difference 

between actual metered electricity usage after an EE program, 

project, or measure is implemented, and a “common practice 

baseline” (CPB). A CPB is the equipment that would most 

frequently be installed at the time an existing piece of 

equipment fails or is replaced at the end of its effective 

useful life – or that a typical consumer or building owner would 

have continued using for the remainder of the equipment's 

effective useful life – in a given circumstance (i.e., a given 

building type, EE program type or delivery mechanism, and 

geographic region) at the time of EE implementation. It defines 
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what would commonly have happened in the absence of the EE 

interventionprogram, project, or measure. 

The applicable CPB depends on a number of factors, such as 

characteristics of the EE program, project, or measure, the 

delivery mechanism to implement the EE measureby which 

electricity customers are engaged, local consumer and market 

characteristics, and the applicable building energy codes and 

product standards (C&S), including the C&S compliance rate. 

Examples of appropriate CPBs to apply in specific contexts, with 

consideration of these factorscircumstances, which may be 

presumptively approvable, can be found in the EPA’s draft EM&V 

guidance. EE providers must document the selected CPB in their 

EM&V plans, along with clear documentation and discussion of the 

rationale, applicability, and relevant data sources, protocols, 

and other supporting information. Monitoring and verification 

reports must refer to the EM&V plan and confirm that the CPB was 

appropriately applied. 

(2) Methods Used to Quantify Savings from Energy Efficiency 

Programs and Projects

This section discussesproposes criteria that are

presumptively approvable provisions for the general types of 

EM&V methods that EE providers may use to quantify the MWh 

savings from demand-side EE programs, projects, and measures. 
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During the CPP EG’s public comment period, the EPA received 

input indicating that state PUCs typically allow utilities and 

other EE providers to use a range of EM&V methods that reflect 

applicable circumstances and on-the-ground conditions (versus 

mandating which methods must be used in a particular situation). 

Consistent with this approach, the EPA’s presumptively 

approvable provisionsEPA is proposing to offer flexibility for 

EE providers to select from three broad categories of EM&V 

methods to determine savings. 

These categories include project-based measurement and 

verification (M&V),, deemed savings, and comparison group 

approaches such as randomized control trials (RCT). Regardless 

of the approach selected, the EPA is proposing that annual 

savings values must be quantified using these EM&V methods at 

specified time intervals (in years) on a recurring basis over 

the effective useful life of the EE project or measure in order 

to ensure accurate and reliable savings values. To be considered 

presumptively approvable,presumptivey approable, the EPA is 

proposing that EE providers must conduct apply the above methods 

at a minimum of four 4-year intervals for building energy codes 

and product standards; every one, two1, 2 or three3 years for 

publicly- or rate-payer fundedutility-administered EE programs, 

depending on the program type, magnitude of savings, and 
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experience with the program; and annually for large individual 

commercial and industrial projects, unless the EE provider can 

credibly demonstrate why this is not possible and how the 

accuracy and reliability of savings values will be maintained. 

For all demand-side EE used to adjust an emissions rateThe EPA 

is further proposing that, to be presumptively approvable, the 

selected method, associated assumptions, and data sources must 

be identified and described in EM&V plans.

For comparison group approaches, the EPA is propsing that 

states and EE providers can refer to the EPA’s draft EM&V 

guidance for a discussion of industry best-practice protocols 

and guidelines, such as those published by the SEE Action 

Network and the U.S. DOE’s Uniform Methods Protocols (UMP) 

project.. Where feasible, the EPA seeksis proposing to encourage 

the use of RCT methods, which determine savings on the basis of 

energy consumption differences between a treatment group and a 

comparison group, and therefore increase the reliability of 

results.

As noted above, an alternative to comparison group methods 

is the use of deemed savings values, which establish predetermined annual electricity savings values for specific EE 

measures. The EPA is proposing that the use of deemed savings 

values will be presumptively approvable provisions are that 
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deemed if those values (a) beare documented in a publicly 

available database (also known as a Technical Reference Manual) 

that is accessible on a public websiteWeb site, or is otherwise 

readily accessible; (b) specify the conditions for which each 

deemed value can be applied, including but not limited to 

climate zone, building type, and EE implementation mechanism; 

and (c) beare updated at a minimum of every 3 years to reflect 

the per-measure MWh savings documented in ex-post EM&V studies 

apply measurement and verificationM&V or comparison group 

methods. 

For M&V methods, the to be presumptively approvable

provision, the EPA is proposing is that industry best-practice

protocols and/or guidelines must be followed. These include the 

International Performance Measurement and Verification Protocol 

(IPMVP),Examples of acceptable best-practice protocols published 

by the Federal Energy Management Program (FEMP), the American 

Society of Heating, Refrigeration and Air-Conditioning Engineers 

(ASHRAE), and the U.S. DOE’s UMP.guidelines are provided in the 

EPA's EM&V guidance. EE providers can consult the EPA’s EM&V 

guidance to assess the applicability of such protocols and 

guidelines these technical resources to the EE programs and 

projects generating savings, and must document how these one or 

more best-practice protocols or guidelines will be appropriately
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applied in EM&V plans (along with clear documentation and 

discussion of the rationale, applicability, and relevant data 

sources, and other supporting information). The EPA is also 

proposing that monitoring and verification reports must refer to 

the EM&V plan and confirm that the relevant M&V protocol or 

guideline was properly applied.

(3) Quantifying Savings

Regardless of the approach used to quantify and verify MWh 

savings, the EPA is proposing that EM&V plans must describe how 

they will address the following presumptively approvable 

provisions: 

• How major changes in independent variable conditions 

(weather, occupancy, production rates, etc.) that 

affect energy consumption and savings estimates will 

be analyzed.accounted for. The EPA is proposing that

the effects of these changes must be calculated using 

industry best-practices such as real-time conditions 

or normalized conditions that are reasonably expected 

to occur throughout the lifetime of the EE project or 

measure. 

• How the initial installation of EE will be verified 

for EE program categories that involve the 

installation of identifiable measures (e.g., most
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utility consumer-funded EE programs and project-based 

EE are evaluated site-by-site). The EPA is proposing 

that verification is required within the first year of 

program implementation. and that all verification 

activities must be performed using industry bestpractice techniques (e.g., phone or mail surveys, 

document review, site inspections, spot or short-term 

metering). For projects implemented as part of a 

larger program, the EPA is proposing that verification 

can be performed using a sample of projects to 

represent the full program population. 

• How avoided T&D system losses84 will be quantified and 

applied to EE savings determined at the customer 

facility or premises. The EPA is proposing that 

demand-side EE programs (other than T&D efficiency 

measures such as CVR and volt/VAR optimization85) may 

adjust reported savings by using a T&D adder. If such 

 

84 T&D losses are defined as the difference between the quantified 

EGU generation required to serve a customer’s load (measured at 

the EGU bus bar) and the customer’s actual electricity consumption 

(measured at the customer meter).

85 More information about these technologies is in section VIII.F.1 

of the final EGs.
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an adder is applied, the presumptively approvable 

appraochapproach is to use the smaller of 6 percent or 

the calculated statewide annual average T&D loss rate 

(expressed as a percentage) calculated using the most 

recent data published by the U.S. Energy Information 

Agency (EIA)EIA State Electricity Profile.86

• How the duration of EE program or project electricity 

savings will be determined. This must be determined 

using industry best-practice protocols and procedures 

such asinvolving annual verification assessments, 

industry-standard persistence studies, deemed 

estimates of effective useful life (EUL), or a 

combination of all three. 

• How the accuracy and reliability of quantifying MWh 

savings values will be assessed, and the rigor87 of the 

 

86 Estimated losses in MWh, total electric supply, and direct 

electricity use values are available in the U.S. EIA’s State 

Electricity Profiles. See table on Supply and Disposition of 

Electricity (currently Table 10). Direct electricity use refers to 

the electricity generated at facilities that is not put onto the 

electricity grid, and therefore does not contribute to T&D losses.

87 Rigor refers to the level of effort expended to minimize 

uncertainty from factors such as sampling error and bias. The 

higher the level of rigor, the more confident one is that the 

results of the EM&V activities are both accurate and precise. 
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methods used to control the types of bias or error 

inherent to the applied EM&V methods. Sampling of 

populations is appropriate, provided that the 

quantified MWh derived from sampling have at least 90 

percent confidence intervals whose end points are no 

more than +/-10 percent of the estimate. 

• How double counting will be avoided through the use of 

tracking and accounting procedures to ensure that the 

same MWh of electricity savings is not claimed more 

than one time (for example, two EGUs claiming savings 

from the same lighting retrofit). The types of double 

counting that may arise are discussed in the EPA’s 

draft EM&V guidance.

(4) Use of Energy Efficiency EM&V Protocols

In the CPP EG’s public comments, the EPA heard that EM&V 

protocols for demand-side EE are currently in wide use, and that 

they should be continued and encouraged. The agency agrees with 

this observation and is therefore proposing the application of 

industry best-practice protocols and procedures for demand-side 

EE. A In particular, the EPA is proposing that, to be

presumptively approvable provision for, EM&V plans is that they

 
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mustmust specify the use of best-practice protocols and 

procedures, and must also include a clear description and 

documentation of how the relevant protocols and procedures will 

be applied, as well as after-the-fact. EM&V reports must include

documentation in EM&V reports of how theysuch protocols and 

procedures were actually applied. EE providers can refer to the 

EPA’s EM&V guidance document for information about protocols 

that are considered “industry best-practice protocols and 

procedures.”

(5) Eligible Demand-Side Energy Efficiency Programs and Projects.

There has been stakeholder interest expressed through the 

CPP EGEGs rulemaking process in accounting methodsallowing 

states to issue ERCs for quantified and verified MWh savings 

from DS-EE inunder state plans. Consistent with these 

perspectives, the EPA position is proposing that any demand-side 

EE program and, project, or measure that results in MWh savings 

may be potentially eligible to statesgenerate ERCs, including 

under this proposed model trading rule, provided that it 

meetsthey meet the presumptively approvable provisions for 

eligibility described in section &&&,IV.C.3 of this preamble,

and that supporting EM&V is rigorous, transparent, credible,

complete and fulfills the requirements provided in the emission 

guidelinesEGs and the state plan. 
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CommonExamples of potentially eligible demand-side EE 

programsprogram and project types include: 

• Publicly or consumer-payer funded customer-funded 

demand-side management programsutility-administered EE 

programs, including those implemented in low-income 

residences and facilities.

• Project-based EE evaluated site-by-site, for example 

those implemented by ESCOs at commercial buildings and 

industrial facilities.

• State and local government building energy code and 

compliance programs.

• State and local government incremental product energy 

standards.

The EPA’s EM&V guidance contains supplemental information 

about applicable best-practice protocols, methods, and other key 

considerations for quantifying and verifying savings from the 

above-listed EE activities in an accurate and reliable manner. 

The agency also recognizes that the programs and policies listed 

above will evolve and change over the rule period, as new 

technologies emerge and efficiency improves. The agency also 

expects that new EE program types will emerge and expand 

throughout the rule period, and that MWh savings resulting from 

any such programs can similarly be considered if they meet the 
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requirements of the emission guidelinesEGs. 

(6) Requests for Comment on Energy Efficiency EM&V

We take broad comment on each EE EM&V criteriacriterion

described herein and in the proposed rule text, for each type of 

EE activity, project, program, or measure. Specifically, we seek 

comment on the substantive content of the criteria, and we seek 

comment on the level detail provided regarding these criteria 

and whether more or less detail (and what detail) should be 

included in the final model rule. In addition, we seek comment 

on whether some of the EE EM&V criteria (and if so, which 

criteria) included in the draft guidance document 

proposedreleased simultaneously with this proposed rulemaking 

should instead be included in the final model rule, instead of 

in guidance. Similarly, we seek comment on whether some of the 

EE EM&V criteria (and if so, which criteria) included in the 

proposed model rule should instead be addressed in the final 

EM&V guidance. More generally, we seek comment on what EE 

criteria the EPA should described in guidance versus what 

criteria the EPA should specify in the final model, whether or 

not those criteria are already included in the draft guidance or 

draft model rule.

We take broad comment on the appropriate EE EM&V criteria 

for quantifying the electricity savings from every type of EE 
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activityprogram, project, program, or measure. We take broad 

comment on what constitute EE best practices-practice protocols 

and procedures for every type of EE activityprogram, project, 

program, or measure.

We take broad comment on whether, when, and how common 

practice baselines should and should not be used in calculating 

electricity savings from EE activities, projects, programs, and 

measures, including comment on which common practice baselines 

should be used in which circumstances. We also take comment on 

whether some alternative metric should be used in lieu of the 

common practice baseline and, if so, what that metric should be. 

We take broad comment on the appropriateness of quantifying

electricity savings by applying one or more of the following 

methods and comment on all aspects of each method: project-based 

measurement and verification (PB-MV), comparison group 

approaches, or deemed savings. We take further comment on 

circumstances in which it is appropriate (or inappropriate) to 

use each of these methods, including when it is appropriate to 

use random control trials (RCT) and quasi-experimental methods, 

and the circumstances in which they can be encouraged and 

applied in practice (e.g., when a suitable control or 

comparision group can be identified and applied in a costeffective manner). In addition, we take comment on whether the 
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general suitability and applicaton of quantification methods, 

such as RCT, quasi-experimental techniques or other comparison 

group approaches when they are available at reasonable cost for 

purposes of quantifying MWh savings for particular EE programs, 

projects, or measures.

If deemed savings are to be used in quantifying 

electricity savings from an EE program, project, or measure, we 

take comment on the appropriate characteristics and 

presumptively approvable provisions for their use in generating 

qualifying ERCs, including the basis and frequency for their 

determination., and the appropriateness of their application to 

particular EE programs, projects or measures in particular 

states or regions. We further take comment on the presumptively 

approvable provision for public access and input to the 

development of the TRMs used to house the applicable deemed 

savings values. 

We take comment on the minimum and maximum intervals (in 

years) over which electricity savings must be quantified, 

including those time intervals specified in the proposed model 

rule, and we take comment on any factors that must be taken into 

consideration when determining the appropriate time interval for 

specific EE programs, projects, or measures.

Because many states have different EE programs in place 
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today, and we would expect them to build off ofleverage these 

programs if they incorporated EE into a rate-based trading 

scheme with ERCs, it is theoretically possible that an ERC could 

be issued in one state that would not have been issued in 

another, even if both states have rate-based programs in place 

that meet all of the emission guidelines.EGs. The EPA takes 

comment on what criteria it should include in the final model 

rule, and what level of details with respect to those criteria 

that it should include, in order to ensure that an ERC issued 

for an EE activityprogram, project, program,or measure in one 

state reflects the same 1 MWh of energy or electricity saved in 

another state. We further take comment on whether there are 

provisions that the EPA should include in the final model rule 

that would prevent an entity seeking to be issued an ERC 

(whether from EE or energy generation) from forum shopping, in 

an effort to find a state with standards for ERC issuance that 

it deems more lenient or less burdensome than those in another 

state.

We take comment on how to appropriately consider factors 

that affect energy savings in the quantification and 

verification process, including those identified in the proposed 

model rule, and we take comment on whether these factors should 

be addressed in every plan or just certain types of plans. Such 
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factors may include the effect of changes in independent 

factors, effective useful life (and its basis), and interactive 

effects of EE programs, projects, and measures.

We take comment on the circumstances and frequency in which 

savings verification must occur to ensure that EE measures have 

been installed, are functioning, and have the potential to save 

energy.

We take comment on the appropriate steps for avoiding 

double counting, and how such steps should be documented in an 

EM&V plan. In particular, we take comment on the circumstances 

and conditions in which double counting is most likely to occur 

(such asincluding those identified in this section), and the 

presumptively approvable provisions that must be adopted in 

state plans for avoiding and mitigating double counting.

We take comment on the appropriate means by which an EM&V 

plan can ensure the accuracy and reliability of electricity 

savings resultsestimates, including the necessary rigor of the 

methodmethods selected to evaluate the electricity savings, the 

methods used to control all relevant types of bias and to 

minimize the potential for systematic and random error, and the 

potential effects of such bias and error. We further take 

comment on the presumptively approvable provision that samples 

taken to quantify EE program savings must achieve 90/10 
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confidence and precision. 

We take comment on the presumptively approvable approach to 

quantifying the electricity savings that result from avoiding a 

transmission and distribution system loss, including the 

provisions in the proposed model rule, which specify that each 

EM&V plan must measurequantify the transmission and distribution 

loss based on the lesser of 6 percent of the site-level 

electricity savingscomsumption measured at the end use meter or 

the statewide annual average transmission and distribution loss 

rate (expressed as a percentage) from the most recent year that 

is published in the USU.S. EIA State Electricity Profile

expressed as a percentage.. We take comment on the 

appropriateness of including such a restriction in the final 

model rule that no other transmission and distribution loss 

factors may be used in calculating the electricity savings.

We take comment on any additional criteria that we should 

include in the final model rule regarding EE EM&V.

h. Skill Certification Standards 

Using a skilled workforce to implement demand-side EE and 

RE projects and other measures intended to reduce CO2 emissions, 

and to evaluate, measure and verify the savings associated with 

EE projects or the additional generation from performance 

improvements at existing EGU’s are both important. Several 
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commenters pointed out that skill certification standards can 

help to assure quality and credibility of demand-side EE,RE and 

other carbon emission reduction projects. The EPA also 

recognizes that a skilled workforce performing the EM&V is 

important to substantiate the authenticity of emissions 

reductions.

The EPA agrees that in conjunction with other EM&V 

measures discussed in this section, and in the context of the 

model trading rules although this is not an aspect needed for 

presumptive approvability, states are encouraged to include in 

their plan a description of how states will ensure that workers 

installing demand side EE and RE projects, or other measures 

intended to reduce CO2 emissions, as well as workers who perform 

the EM&V of demand side EE and existing EGU performance will be 

certified by a third party entity that:

• Develops a training or competency based program 

aligned with a job task analysis and/or certification 

scheme;

• Engages with subject matter experts in the development 

of the job task analysis and/or certification schemes 

that represent appropriate qualifications, categories 

of the jobs, and levels of experience;

• Has clearly documented the process used to develop the 
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job task analysis and/or certification schemes, 

covering such elements as the job description, 

knowledge, skills, and abilities; 

• Has pursued third-party accreditation aligned with 

consensus-based standards, for example ISO/IEC 17024 

or IREC 14732.

Examples of such entities include: parties aligned with the 

Department of Energy’s (DOE)DOE’s Better Building Workforce 

Guidelines and validated by a third party accrediting body 

recognized by DOE; or parties aligned with an apprenticeship 

program that is registered with the federal Department of Labor 

(DOL), Office of Apprenticeship; or with a state apprenticeship 

program approved by the DOL, or by another skill certification 

validated by a third party accrediting body can help to 

substantiate the authenticity of emission reductions due to 

demand-side EE and RE and other carbon emission reduction

measures.

9. ERC Transfers and Trading

All affected EGUs that may be subject to this proposed 

federal plan would be required to be a part of the allowance 

tracking and compliance system (ATCS) that the EPA runs, 

although the affected EGUs that are regulated under the ratebased federal plan would use ERCs as a compliance instrument, 
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not allowances. To register to participate in the ATCS an 

affected EGU must submit designated representative information. 

More information on the designated representatives is described 

belowabove in section IV.ED.1 of this preamble &&&.. Non-EGUs 

who wish to participate (e.g., RE sources) may submit 

registration criteria to participate in the ATCS. The ATCS will 

allow the trading and holding of ERCs that qualify for CPP 

compliance in a system that also will be used to determine 

compliance. Quarterly, an affected EGU under the federal plan 

must submit information and data consistent with part 75.88 These 

quarterly submission dates are the 30th of April, July, October 

and January corresponding with the quarterly data ending the 

month previous the submission deadline (e.g., an April 30, 2024 

submission would include data from January through March of 

2024). The data that are posted online would be publicly 

available. 

Non-EGU ERC generating sources are required to submit 

generation data annually (see &&& section IV.FC.3 of this 

preamble for a comprehensive discussion of non-EGU ERC 

generating sources). The data must follow the EM&V procedures 

delineated in section IV.F.4D.8 of this preamble. Because of the 

 

88 See section IV.D.11 of this preamble for more information.
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required rigor of the EM&V process, the EPA provides a time 

frame of January 1 to [&&& June 1] of the year that follows the 

data’s inception to complete all EM&V processes (e.g, 2024 RE 

data must go through the EM&V process and be submitted to the 

EPA no later than &&& June 1, 2025). After receiving all 

emission and generation data from ERC generating sources and 

affected EGUs, the EPA will issue ERCs through a NODA as 

described in section IV.E.4 inD.6 of this preamble. The EPA is 

proposing to issue ERCs annually. ERCs are acquired and traded 

throughout the compliance period. An affected EGU is responsible 

to hold sufficient ERCs that qualify for CPP compliance in its 

ATCS compliance account by November 1 at midnight of the year 

following the conclusion of the compliance period.89

The process for transferring ERCs from one account to 

another is quite simple. A transfer would be submitted 

providing, in a format prescribed by the agency, the account 

numbers of the accounts involved, the serial numbers of the ERCs 

involved, and the name and signature of the transferring 

authorized account representative or alternate. If the transfer 

form containing all the required information were submitted to 

the EPA and, when the Administrator attempted to record the 

 

89 This true-up process is further described in section IV.D.8 of 

this preamble.
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transfer, the transferor account included the ERCs identified in 

the form, the Administrator would record the transfer by moving 

the ERCs from the transferor account to the transferee account 

within 5 business days of the receipt of the transfer form. 

10. Compliance with Emissions Standards

Once the compliance period has ended, affected EGUs would 

have a window of opportunity to evaluate their reported 

emissions and obtain any ERCs that they might need to cover 

their emissions during the compliance period. The agency 

proposes to require sources to demonstrate compliance, i.e., ERC

true-up, on November 1 of the year after the last year in the 

compliance period. For example, if the first compliance period

comprises the three years 2022, 2023, and 2024, then the ERC

transfer deadline90 for that first compliance period (after which 

point the EPA would evaluate compliance) would be on November 1, 

2025. The agency also requests comment on an earlier 

allowanceERC transfer deadline, such as June 1 or March 1, of 

the year after the last year in the compliance period. Each ERC 

issued in the proposed rate-based trading program would, if 

applied, be averaged into the compliance rate as one MWh of 

 

90 The “ERC transfer deadline” is the deadline for transferring 

allowances that can be used for compliance in the previous 

compliance period to a source’s compliance account. 
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energy with zero CO2 emissions deemed associated with it for the 

compliance period that includes the year for which the ERC was 

issued or be averaged into a later compliance period. 

Consequently, each affected EGU would need, as of the ERC 

transfer deadline, to have in its compliance account enough ERCs 

usable for its compliance obligations for the compliance period. 

The authorized account representative could identify specific 

ERCs to be applied, but, in the absence of such identification 

or in the case of a partial identification, the Administrator 

would deduct on a first-in, first-out basis. The ERCs that are 

used to meet compliance obligations are moved from the 

compliance account to the EPA’s retirement account. ERCs that 

are deducted for compliance will remain in the system in an EPA 

account, which ensures they will not be used again.

The EPA will use the submitted generation, CO2 emissions and 

ERCs in the affected EGU’s compliance account to calculate an 

average emission rate for the EGU. It is the responsibility of 

an affected EGU to calculate the number of ERCs that will need 

to be held in a compliance account to meet the EGU’s compliance 

obligations. The method for determining the quantity of ERCs 

needed to meet compliance obligations has been discussed 

previously in an example. To reiterate the process, the affected 

EGU would need to solve for the number of zero-emitting MWh 
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(i.e., ERCs) that would need to be added to the total MWh of the 

EGU to make the adjusted emission rate equal to the emission 

standard. 

AAAAAAAAAAAAAAAA EEEEEE EEEEEE RRRR = MM oo CCCC2 (llll )

GG GG (MMMMh) + MMMMh EE

This equation can be rearranged to:

MMMMh EE = MM oo CCCC2 (llll )

AAAAAAAAAAAAAAAA EEEEEE EEEEEE RRRR ( llll

MMMMh)

− GG GG (MMMMh)

If an affected EGU fails to hold sufficient ERCs to comply 

with its emission standard then, upon notification of the 

deficiency, the owners and operators of the affected EGU must 

provide, for deduction by the Administrator, two ERCs as soon as 

available for every ERC that the owners and operators failed to 

hold as required to cover emissions, in addition to the ERCs 

owed for compliance in that next period. The owed ERCs will be 

deducted from the EGU’s compliance account as soon as they are 

available in this account; the Administrator will not wait until 

the next true-up date to make this deduction. The two ERCs owed 

for each ERC needed for compliance is in addition to any other 

recourse provided in sections 113 (a) – ()–(h) or section 304 of 

the Clean Air ActCAA. This requirement to surrender two times 

the ERCs needed to make up the shortfall for the prior period is 

an ongoing obligation until compliance is achieved, and there is 
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an ongoing obligation to comply in the current period. Failure 

to surrender these replacement ERCs is an additional violation 

that may be subject to federal enforcement. The EPA solicits 

comment on sources owing two ERCs to make up for each 

insufficient ERC in previous compliance periods and whether two 

for one is the proper make-up rate or whether there should be a 

stricter or a more lenient ratio. 

The EPA believes that it is important to include a 

requirement for an automatic deduction of ERCs. The deduction of 

one ERC per ERC that the owners and operators failed to hold 

would offset this failure. The deduction of another ERC per ERC 

that the owners and operators failed to hold provides a strong 

incentive for compliance with the ERC-holding requirement by 

ensuring that non-compliance would be a significantly more 

expensive option than compliance. This is consistent with other 

existing trading programs.

11. Other ERC Tracking and Compliance Operations Provisions

These sections also would provide that the Administrator 

could, at his or her discretion and on his or her own motion and 

consistent with existing federal trading programs, correct any 

type of error that he or she finds in an account in the ATCS. In 

addition, the Administrator could review any submission under 

the rate-based trading program, make adjustments to the 
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information in the submission, and deduct or transfer ERCs based 

on such adjusted information. These provisions are a standard 

part of other trading programs administered by the EPA including 

the Acid Rain ProgramARP and Cross State Air Pollution Rule 

(see, e.g., 40 CFR 72.96, 73.37, 97.427, and 97.428). The EPA 

solicits comment on potential alternatives for error correction 

that is simpler or more efficient. 

12. Banking of ERCs

The EPA is proposing to allow unlimited banking or ERCs 

within and between the interim and final compliance periods. 

This means that if an affected EGU has more ERCs than are 

necessary during true-up, it may save (i.e., bank) those ERCs 

for application during a future compliance period. The EPA 

requests comment on whether there should be a quantitative limit 

or cap on the number of ERCs that can be banked. The EPA also 

requests comment on whether an ERC should be eligible to be 

banked between the interim and final compliance periods. The EPA 

is also proposing that ERCs will not expire after any duration 

of time. Other trading rules that the EPA has instituted (e.g., 

CSAPR) do not have expiration on the tradable properties. The 

EPA requests comment on the shelf-life of an ERC. 

ERC “borrowing” is a flexibility that the EPA is not 

proposing, but is soliciting comment on. ERC borrowing is the 
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concept that an affected EGU may use an ERC that the EGU will 

acquire in a future compliance period to meet its current 

compliance obligations. The EPA requests comment on a 

methodology that would allow ERC borrowing while maintaining the 

integrity of the compliance obligations. The EPA also has 

reservations due to the fact that future ERC generation is not 

guaranteed. 

13. Emissions Monitoring and Reporting

The EPA would require that emission and generation data be

reported to the EPA quarterly starting on April 30, 2022, and 

continuing every three3 months thereafter (i.e., the 30th of 

April, July, October, and January). The EPA proposes that

affected EGUs subject to the rate-based federal plan trading 

program would monitor and report CO2 emissions in accordance with 

40 CFR part 75. The EPA is proposing to require affected EGUs in 

all states covered by the rate-based federal plan trading 

program to monitor and report CO2 emissions by and output data by 

January 1, 2022. Quarterly reporting would be required, with 

each quarterly report due to the Administrator 30 days after the 

last day in the quarter. The reporting would be in accordance 

with 40 CFR part 75.60. The use of part 75 certified monitoring 

methodologies would be required. Many affected EGUs that might 

be covered by the proposed federal plans will generally have no 
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changes to their monitoring and reporting requirements and will 

continue to monitor and submit reports under part 75 as they 

have under existing programs. The EPA anticipates fewer than 50 

(approximately 10 of these affected EGUs are coal fired with the 

remainder being gas and oil fired that will qualify for an 

excepted monitoring methodology) affected EGUs, that would not 

otherwise be subject to the Acid Rain ProgramARP, will have to 

purchase and install additional continuous emissions monitoring 

system (CEMS) and data handling systems or upgrade existing 

equipment in order to meet the monitoring and reporting 

requirements of this program. Several of the affected EGUs not 

otherwise subject to the Acid Rain ProgramARP are subject to the 

MATS program and therefore will have already installed stack 

flow rate and/or CO2 monitors in order to comply with the MATS 

rule which are also necessary to comply with this rule. The CEMS 

used to comply and report data for MATS will be used for this 

rule to generate and report CO2 emissions data without having to 

install duplicative monitors. The same CO2 and stack gas flow 

rate monitored data used in conjunction with Hgmercury and other 

CEMS to calculate a toxic pollutant emission rate may be used to 

calculate a CO2 mass or CO2 emission rate for this program. 

RGGI,The Regional Greenhouse Gas Initiative (RGGI), ARP, MATS 

and this rule all refer to CEMS installed and certified in 
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accordance with 40 CFR part 75. RGGI and ARP currently require 

the reporting of CO2 mass emissions on an hourly basis and 

cumulative totals at the end of each calendar quarter. The same 

monitors and data collected may be used for multiple purposes 

for RGGI, ARP, MATS and this rule. Relying on the same monitors 

that are certified and quality ensured in accordance with 40 CFR 

part 75 ensures cost efficient, consistent, and accurate data 

that may be used for different purposes for multiple regulatory 

programs. The majority of the affected EGUs covered by this rule 

are already affected by the Acid Rain and/or Regional Greenhouse 

Gas InitiativeorRGGI programs and will have minimal additional 

monitoring and reporting requirements.

The EPA also requests comment on requiring monitoring and 

reporting of CO2 mass and net generation for the year before the 

initial compliance period begins, i.e., to commence January 1, 

2021. Only monitoring and reporting would be required in 2021 —

compliance with an enforceable emission standard would commence 

on the compliance period schedule that is detailed in section 

IV.E.3III.D of this preamble.

E. Federal Plan and State Plan Interactions

1. Interstate Trading

The EPA proposes that all affected EGUs within states that 

are covered by the federal plan, if a rate-based federal plan is 
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finalized for two or more states, would be allowed to trade with 

one another since there will be an assured commonality in the 

ERC currency and criteria surrounding the trading program. In 

addition, the EPA proposes, consistent with the provision for 

“ready-for-interstate-trading” plans in the EGs that affected 

EGUs located in states with approved ready-for-interstatetrading state plans using the sub-categorized uniform rate 

standards, and a common credit currency (i.e., ERCs representing 

one zero-emitting MWh) may trade with affected EGUs operating 

under the federal trading program established in this federal 

plan. 

Rate-based EGUs subject to the federal plan and rate-based 

EGUs in ready-for-interstate-trading state plans will be able to 

trade ERCs seamlessly across jurisdictional borders because of 

the assurances of being presumptively approvable. Ready-forinterstate-trading states must submit information that lists all 

affected EGUs and the EGU type to the Administrator to be able 

to trade within the federal trading program. To be able to trade 

in the federal trading program an affected EGU that is subject 

to a ready-for-interstate-trading state plan must: (1) Certify

and authorize a designated representative per section &&& 

IV.ED.1 of this preamble; and (2) register a general account in 

the federal trading program, ATCS, in order to have a means of 
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transferring ERCs with entities operating in the federal trading 

program. An affected EGU under a state plan will not register a 

compliance account in the federal system because it will not be 

demonstrating compliance under the federal plan. Compliance will 

be achieved in the EGU’s corresponding state plan. Affected EGUs 

under a state plan have the ability to acquire ERCs through the 

federal trading program. These ERCs will be stored in the EGU’s 

general account in the federal trading program. To use these 

ERCs for compliance purposes, the ERCs must be transferred to 

the EGU’s compliance account in the state’s program. The EPA 

proposes to provide software to states to maintain a state’s 

compliance and tracking program. A state’s program will have the 

capability to interact with the federal trading program and 

software, ATCS, for transferring ERCs if the state is ready-forinterstate-trading. A state’s program can be tailored to meet 

its needs while still providing a platform for a state to be 

transferring ERCs between the state’s system and the federal 

trading program. ERCs can flow between a state system and the 

federal trading program bilaterally. The EPA acknowledges that 

states may have additional criteria for generating ERCs that are 

not outlined as part of the federal plan, but because the EPA 

will have vetted these criteria through a state plan approval 

these ERCs will be able to be traded within the federal trading 
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program. 

2. Treatment of States Entering or Exiting the Trading Program.

The EPA proposes that a rate-based trading federal plan may

be replaced by a state plan for a future compliance period. The 

EPA is proposing that a state must transition to a state plan at 

the conclusion of a federal plan compliance period. The EPA 

requests comment on whether there are reasons that a state 

should be allowed to transition from a federal plan to a state 

plan in the middle of a compliance period and if so what 

requirements should be put in place to do so while ensuring the 

integrity of both the federal plan and the state plan and while 

enabling the affected EGUs covered by the plans to understand 

and meet their compliance requirements. If a state subject to 

the federal plan transitions to a state plan, any affected EGU 

impacted by the change remains responsible for meeting any 

outstanding obligations under the federal plan. To make the 

transition to a state plan, a state must have an approved state 

plan as laid out in the CPP preamble sectionsections VIII.D and 

VIII.E of the final EGs. 

V. Mass-based Implementation Approach

A. Trading Program Overview

In addition to the rate-based implementation approach 
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discussed above, the EPA is proposing a mass-based 

implementation approach for the federal plan. As with the ratebased approach, this proposed federal plan is also a proposed 

model trading rule that states can adopt. The mass-based 

approach that the agency proposes to implement is a mass-based 

trading program (i.e., an emissions budget trading program, also 

referred to as an “allowance system”). This section provides a 

brief overview of the proposed mass-based trading program. The 

next sections describe the various elements of the proposed 

trading program in further detail.

A mass-based trading program establishes an “aggregate 

emissions limit” that specifies the maximum amount of emissions 

authorized from affected EGUs included in the program, and 

creates allowances that authorize a specific quantity of 

emissions. The total number of allowances created are equal to, 

and constitute, the emissions budget or the aggregated emissions 

limit expressed in terms of short tons of emissions. The EPA is 

proposing that allowances be issued in short tons for the 

federal plan.

Each facility with affected EGUs in the program must 

surrender allowances equal in number to the quantity of the

emissions of its affected EGUs during the compliance period. A

facility with affected EGUs may buy allowances from, or transfer 
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or sell allowances to, other affected EGUs or other entities 

that participate in the market. A mass-based trading program 

provides sources with great flexibility in choosing compliance 

strategies.

In the proposed mass-based trading program for the federal 

plan, the aggregate emissions limit for a state is its statewide 

mass-based emission goal (or “mass goal”) as finalized in the 

Clean Power Plan EGs. The proposed approach to linking states 

for interstate allowance trading is detailed in section III.A.1

of this preamble; in an interstate trading program the aggregate 

emissions limit is the sum of the mass goals for the covered 

states. 

The EPA believes that a broad trading region provides 

greater opportunities for cost-effective implementation of 

controls compared to a smaller region. Therefore, the agency 

proposes that an affected EGU in any state covered by the 

proposed mass-based trading federal plan may use for compliance 

an allowance distributed in any other state covered by the massbased trading federal plan. The EPA also proposes to provide for 

allowance trading between affected EGUs and other entities in

states with approved mass-based-trading state plans that meet 

the conditions specified in section III.A.1 of this preamble, 

above, and affected EGUs and other entities in any state covered 
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by the federal plan mass-based trading program.

A mass-based trading program can provide environmental 

certainty at lower cost than other policy mechanisms, because it 

assures the specified emissions outcome while maximizing 

compliance flexibility available to individual affected EGUs. 

Further, allowance banking in such a program creates an 

incentive to make reductions earlier than required. Mass-based 

trading programs are relatively simple to operate, which reduces 

administrative time and cost. Additionally, to inform the massbased trading approach proposed here, the EPA draws upon more 

than two decades of experience implementing federallyadministered mass-based emissions budget trading programs 

including the Acid Rain ProgramARP SO2 trading program, the NOX

Budget Trading Program, the Clean Air Interstate RuleCAIR, and 

the Cross-State Air Pollution RuleCSAPR.

In the proposed mass-based trading program federal plans, 

the emissions limits in each state would be the mass goals that 

the EPA promulgated in the Clean Power Plan EGs (if there is 

interstate trading then the sum of the mass goals for the states 

in the trading program would constitute the aggregate emissions 

limit). The total amount of allowances distributed in each state

for each year would sum to the state’s mass goal for that year. 

As detailed in section V.E of this preamble, the EPA is 
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proposing that a state covered by the federal plan can determine 

its own approach to distribute allowances, and believes that 

state allocation has important merits. The EPA would distribute 

allowances in a state if the state does not choose to do so, as 

detailed below.

Each allowance would authorize the emission of one short

ton of CO2 during the compliance period applicable to the 

allowance’s vintage year or a later compliance period. The 

proposed approach to distribute allowances, including three

types of allowance set-asides, is discussed in section V.D., of 

this preamble, below.

After each compliance period, an affected EGU would 

surrender for compliance an amount of allowances equal to its

emissions during the course of the compliance period. See 

section V.C of this preamble for the proposed length of the 

multi-year compliance periods. Allowances could be transferred,

bought, sold, or banked (carried over for future use) and any 

party could participate in the allowance market. The EPA is not 

proposing allowance “borrowing” (i.e., the bringing forward of 

future-period allowances for use in an earlier period); the 

multi-year compliance periods inherently provide the flexibility 

to schedule relatively greater emission reductions for later 

years within each period, as discussed further in section V.C.
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of this preamble. In the proposed mass-based trading program, 

the emission standard applied to individual affected EGUs is the 

requirement to surrender emission allowances equal to reported 

emissions for each compliance period.

The EPA also proposes that a state may choose to replace 

the federal-plan allowance-distribution provisions with its own 

allowance-distribution provisions (i.e., to determine the 

distribution of allowances for its EGUs or other entities) using 

a state allowance-distribution methodology. State allowance 

distribution can have important advantages, because it allows a 

state to design and shape allowance allocation to its specific 

goals and characteristics, and because states may have 

additional flexibility on allocation approaches, including 

auctions. See section V.E of this preamble for further 

discussion of the proposed approach for state-determined

allowance-distribution methodologies.

This proposed requirement to hold and surrender allowances 

equal to emissions for each compliance period would apply to all 

reported emissions from a facility’s affected EGUs including any 

emissions from co-fired biomass if biomass is included as an 

eligible measure. Section &&&IV.FC.3 of this preamble discusses 

an approach on which the EPA requests comment on the inclusion 

of biomass as an eligible measure and on a proposed option where 
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the agency would identify qualifyingqualified biomass feedstocks 

(i.e., biomass feedstocks that are demonstrated to be a method 

to control increases of CO2 levels in the atmosphere) and 

potential methods for demonstrating compliance, and thus reduce 

the mass emissions attributed to a biomass co-fired affected 

EGU. If the EPA took such an approach, then for purposes of 

compliance with the proposed mass-based federal plan trading 

program, the affected EGU would need to hold allowances equal to 

its emissions less the emissions attributed to the co-fired 

qualified biomass; such an approach would reduce the number of 

allowances the affected EGU would need to hold to demonstrate 

compliance. The EPA requests comment on this approach.

B. Statewide Mass-based Emissions Goals

In the Clean Power Plan EGs the EPA established statewide 

mass-based emission goals (“mass goals”) for all states that are 

equivalent to the rate-based goals. As discussed in section V.C

of this preamble, below, the EPA proposes to implement the massbased trading program with multi-year compliance periods that 

are consistent with the compliance timing provisions in the 

Clean Power Plan EGs, i.e., two three-year compliance periods 

followed by a two2-year compliance period in the Interim Period, 

and successive two2-year periods in the Final Period. In the 

Clean Power Plan EGs, the EPA established mass goals for all 
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states for this pattern of compliance periods. The EPA proposes 

to use those mass goals promulgated in the Clean Power Plan EGs 

as the mass limits (i.e., emissions budgets) for any state

covered by the mass-based trading program (or, if implementing 

interstate trading, then the EPA would use the sum of a covered 

group of states’ mass goals as the aggregate mass limit). The 

EPA is not opening for comment the determinations, made in the 

Clean Power Plan EGs, of each state’s mass goals. The mass goals

are provided for convenience in Table ___ 8of this preamble.

Table ___8. Statewide Mass-Based Emission Goals (“Mass Goals”)

(Short Tons)

State

Interim period Final 

period

Step 1

2022-2024 

Step 2

2025-2027 

Step 3

2028-2029 

2030-2031

and 

thereafter 

Alabama

 

66,164,470 

 

60,918,973 

 

58,215,989 

 

56,880,474 

Arizona

 

35,189,232 

 

32,371,942 

 

30,906,226 

 

30,170,750 

Arkansas

 

36,032,671 

 

32,953,521 

 

31,253,744 

 

30,322,632 

California

 

53,500,107 

 

50,080,840 

 

48,736,877 

 

48,410,120 

Colorado

 

35,785,322 

 

32,654,483 

 

30,891,824 

 

29,900,397 

Connecticut

 

7,555,787 

 

7,108,466 

 

6,955,080 

 

6,941,523 

Delaware

 

5,348,363 

 

4,963,102 

 

4,784,280 

 

4,711,825 

Florida

 

119,380,477 

 

110,754,683 

 

106,736,177 

 

105,094,704 

Georgia

 

54,257,931 

 

49,855,082 

 

47,534,817 

 

46,346,846 
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Idaho

 

1,615,518 

 

1,522,826 

 

1,493,052 

 

1,492,856 

Illinois

 

80,396,108 

 

73,124,936 

 

68,921,937 

 

66,477,157 

Indiana

 

92,010,787 

 

83,700,336 

 

78,901,574 

 

76,113,835 

Iowa

 

30,408,352 

 

27,615,429 

 

25,981,975 

 

25,018,136 

Kansas

 

26,763,719 

 

24,295,773 

 

22,848,095 

 

21,990,826 

Kentucky

 

76,757,356 

 

69,698,851 

 

65,566,898 

 

63,126,121 

Lands of the Fort Mojave 

Tribe

 

636,876 

 

600,334 

 

588,596 

 

588,519 

Lands of the Navajo Nation

 

26,449,393 

 

23,999,556 

 

22,557,749 

 

21,700,587 

Lands of the Uintah and Ouray 

Reservation

 

2,758,744 

 

2,503,220 

 

2,352,835 

 

2,263,431 

Louisiana

 

42,035,202 

 

38,461,163 

 

36,496,707 

 

35,427,023 

Maine

 

2,251,173 

 

2,119,865 

 

2,076,179 

 

2,073,942 

Maryland

 

17,447,354 

 

15,842,485 

 

14,902,826 

 

14,347,628 

Massachusetts

 

13,360,735 

 

12,511,985 

 

12,181,628 

 

12,104,747 

Michigan

 

56,854,256 

 

51,893,556 

 

49,106,884 

 

47,544,064 

Minnesota

 

27,303,150 

 

24,868,570 

 

23,476,788 

 

22,678,368 

Mississippi

 

28,940,675 

 

26,790,683 

 

25,756,215 

 

25,304,337 

Missouri

 

67,312,915 

 

61,158,279 

 

57,570,942 

 

55,462,884 

Montana

 

13,776,601 

 

12,500,563 

 

11,749,574 

 

11,303,107 

Nebraska

 

22,246,365 

 

20,192,820 

 

18,987,285 

 

18,272,739 

Nevada

 

15,076,534 

 

14,072,636 

 

13,652,612 

 

13,523,584 

New Hampshire

 

4,461,569 

 

4,162,981 

 

4,037,142 

 

3,997,579 

New Jersey

 

18,241,502 

 

17,107,548 

 

16,681,949 

 

16,599,745 

New Mexico

 

14,789,981 

 

13,514,670 

 

12,805,266 

 

12,412,602 

New York

 

35,493,488 

 

32,932,763 

 

31,741,940 

 

31,257,429 
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North Carolina

 

60,975,831 

 

55,749,239 

 

52,856,495 

 

51,266,234 

North Dakota

 

25,453,173 

 

23,095,610 

 

21,708,108 

 

20,883,232 

Ohio

 

88,512,313 

 

80,704,944 

 

76,280,168 

 

73,769,806 

Oklahoma

 

47,577,611 

 

43,665,021 

 

41,577,379 

 

40,488,199 

Oregon

 

9,097,720 

 

8,477,658 

 

8,209,589 

 

8,118,654 

Pennsylvania

 

106,082,757 

 

97,204,723 

 

92,392,088 

 

89,822,308 

Rhode Island

 

3,811,632 

 

3,592,937 

 

3,522,686 

 

3,522,225 

South Carolina

 

31,025,518 

 

28,336,836 

 

26,834,962 

 

25,998,968 

South Dakota

 

4,231,184 

 

3,862,401 

 

3,655,422 

 

3,539,481 

Tennessee

 

34,118,301 

 

31,079,178 

 

29,343,221 

 

28,348,396 

Texas

 

221,613,296 

 

203,728,060 

 

194,351,330 

 

189,588,842 

Utah

 

28,479,805 

 

25,981,970 

 

24,572,858 

 

23,778,193 

Virginia

 

31,290,209 

 

28,990,999 

 

27,898,475 

 

27,433,111 

Washington

 

12,395,697 

 

11,441,137 

 

10,963,576 

 

10,739,172 

West Virginia

 

62,557,024 

 

56,762,771 

 

53,352,666 

 

51,325,342 

Wisconsin

 

33,505,657 

 

30,571,326 

 

28,917,949 

 

27,986,988 

Wyoming

 

38,528,498 

 

34,967,826 

 

32,875,725 

 

31,634,412 

C. Compliance Timing and Allowance Banking

The EPA proposes to evaluate compliance (i.e., compare 

emissions from affected EGUs to allowances held by facilities) 

in multi-year periods. A multi-year compliance period provides 

greater flexibility to affected EGUs and reduces administrative 
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burden, compared to a single-year compliance period. The EPA 

seeks to strike a reasonable balance between providing 

flexibility and reducing burden while assuring that any 

noncompliance can be addressed in a timely fashion. 

The compliance periods in the proposed mass-based trading 

program would be the same as promulgated in the Clean Power Plan 

EGs, i.e., the interim period would be divided into three 

compliance periods: a three3-year compliance period (2022 

through 2024), a second three3-year compliance period (2025 

through 2027), and then a two2-year compliance period (2028 and 

2029), for the Interim Period. As in the EGs, the Final Period 

would be divided into successive two2-year compliance periods 

commencing in 2030. The EPA would evaluate compliance only after 

the end of a compliance period in the mass-based trading federal 

plan, e.g., if a compliance period is three3 years long, the 

agency would evaluate compliance only after the end of the third 

year in the period. The EPA is not reopening for comment the 

compliance periods promulgated in the Clean Power Plan EGs.

Some existing greenhouse gasGHG mass-based trading programs

(i.e., emissions budget trading programs) use multi-year 

compliance periods. The Regional Greenhouse Gas Initiative 

(RGGI) uses three3-year compliance periods, along with 

intervening compliance requirements. The RGGI intervening 
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compliance requirement is that sources must hold allowances to 

cover 50 percent of emissions for the first two calendar years 

of each three3-year compliance period; at the end of each 

three3-year compliance period sources must hold allowances to 

cover 100 percent of emissions for the period and allowances 

already deducted for the intervening requirement are subtracted 

from the three3-year obligation.91 The California Air Resources 

Board (CARB) Cap-and-Trade Program also uses three3-year 

compliance periods, along with intervening compliance 

requirements. The CARB intervening requirement is to evaluate 

compliance on 30 percent of each source’s previous year’s 

emissions every year, and evaluate compliance for the remainder 

of emissions every three3 years.92 The EPA proposes to evaluate 

compliance after each multi-year compliance period and is not 

proposing to implement intervening compliance requirements such 

as those in the RGGI or CARB programs, however, the agency 

requests comment on the inclusion of such requirements.

The EPA recognizes that the compliance periods provided for 

 

91 RGGI, Summary of RGGI Model Rule changes: February 2013. 

http://www.rggi.org/docs/ProgramReview/_FinalProgramReviewMaterials/Model_Ru

le_Summary.pdf Accessed June 9, 2015.

92Overview of ARB Emissions Trading Program. 

http://www.arb.ca.gov/cc/capandtrade/guidance/cap_trade_overview.pdf 

Accessed June 9, 2015.
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in this rulemaking are longer than those historically and 

typically specified in CAA rulemakings. As reflected in longstanding CAA precedent, “[t]he time over which [the compliance

standards] extend should be as short term as possible and should 

generally not exceed one month.” See e.g., June 13, 1989 

Guidance on Limiting Potential to Emit in New Source Permitting 

and January 25, 1995 Guidance on Enforceability Requirements for 

Limiting Potential to Emit through SIP and §112 Rules and 

General Permits. The EPA determined that the longer compliance 

periods provided for in this rulemaking are acceptable in the 

context of this specific rulemaking because of the unique 

characteristics of this rulemaking, including that CO2 is longlived in the atmosphere, and this rulemaking is focused on 

performance standards related to those long-term impacts.

The EPA proposes that allowances may be banked for use in 

any future compliance period, with no restriction on the use of 

banked allowances, including from the Interim Period (2022 

through 2029) into the Final Period (2030 and thereafter). The 

agency requests comment on the proposal to provide for unlimited 

allowance banking including the banking of Interim-Period 

allowances for use during the Final Period.

Allowance “borrowing” is a type of timing flexibility 

wherein allowances from a future compliance period may be 
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“brought forward” and used for compliance in an earlier 

compliance period (thus reducing the amount of allowances 

available for the future period). The EPA notes that the 

proposed multi-year compliance periods inherently provide the 

flexibility to emit at relatively higher amounts in earlier 

years of a given compliance period by using allowances from 

future years within each compliance period (e.g., if the first 

compliance period covers years 2022 through 2024, a vintage 2024 

allowance could be used to cover a ton emitted in 2022). The EPA 

is not proposing to allow allowance borrowing across compliance 

periods in the mass-based trading federal plans; however the 

agency is requesting comment on the use of borrowing across 

compliance periods.

Allowance borrowing across compliance periods would 

increase the complexity of the proposed mass-based trading 

program and reduce the flexibility for states to replace the 

federal plan with an approved state plan. First, in order for 

borrowing to occur, the EPA would have to make allowances from 

future compliance periods available early so that sources could 

use these future allowances in earlier compliance periods. The 

EPA proposes to record allowances in source accounts for one 

compliance period at a time in order to maximize the 

opportunities for a state to replace the federal plan (or 
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replace the allowance-distribution provisions of the federal 

plan) with an approved state plan (or approved state allowancedistribution methodology). The EPA proposes to allow a state to 

replace the mass-based trading federal plan (or the federal-plan 

allowance-distribution provisions) with a state plan (or state 

allowance-distribution methodology) for a compliance period for 

which the agency has not yet recorded allowances in source 

accounts. Recording allowances for multiple compliance periods 

at once – in order to make future-period allowances available 

for borrowing – would therefore limit these opportunities for 

states to take over implementation (or implementation of the 

allowance-distribution).

If allowance borrowing from a future compliance period were

allowed, and the EPA provided the opportunity for a state to 

replace the federal plan for a year for which allowances had 

already been borrowed and retired for compliance in an earlier 

period, those borrowed allowances would constitute additional 

emissions beyond the levels specified in the Clean Power Plan 

EGs. In that event, the EPA would then need to address whether 

and how to remove allowances from circulation to prevent 

inflation of the allowable emissions at affected EGUs in the 

remaining states subject to the federal plans (to “repay” the 

borrowed allowances). To avoid disruption to sources already 
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subject to the mass-based trading federal plan, the EPA is not 

proposing to allow allowance borrowing across compliance 

periods. 

Although not proposing to provide for allowance borrowing

across compliance periods, the agency requests comment on the 

potential inclusion of allowance borrowing in the proposed massbased trading federal plans, including from how far into the 

future to allow allowances to be borrowed, how inclusion of 

borrowing would affect opportunities for states to take over 

implementation of the EGs (or implementation of the allowancedistribution provisions in the mass-based trading federal plan), 

how to address removing the extra allowances from circulation 

that would result if borrowed allowances originate in a state 

that subsequently withdraws from the mass-based trading program, 

and on other complexities that borrowing across compliance 

periods would introduce.

The agency proposes to require sources to demonstrate 

compliance, i.e., allowance true-up, on May 1 of the year after 

the last year in the compliance period. For example, if the 

first compliance period comprises the three years 2022, 2023, 

and 2024, then the allowance transfer deadline93 for that first 

 

93 The “allowance transfer deadline” is the deadline for 
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compliance period (after which point the EPA would evaluate

compliance) would be on May 1, 2025. The agency also requests 

comment on an earlier or later allowance transfer deadline. 

The EPA proposes to evaluate compliance (i.e., allowance 

true-up) at the facility level, not at the individual affectedEGU level, in the mass-based trading program. Facility-level 

compliance may ease implementation compared to unit-level 

compliance; each facility has a single compliance account in 

which to hold allowances to cover emissions from all its 

affected EGUs rather than having individual unit-level 

compliance accounts. Fewer accounts may make it easier for the 

designated representatives to manage their allowances. The EPA 

has adopted facility-level compliance in previous emissions 

budget-trading programs including the Acid Rain ProgramARP (70 

FR 25162), Clean Air Interstate Rulethe CAIR (70 FR 25162), and 

Cross-state Air Pollution Rulethe CSAPR (76 FR 48208). The EPA 

would continue to track unit-level emissions – while evaluating 

compliance at the facility level – allowing us to track 

increases and decreases of pollutants at individual EGUs.

 

transferring allowances that can be used for compliance in the 

previous compliance period to a source’s compliance account. For 

further information see section V.G of this preamble.
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D. Initial Distribution of Allowances

Establishing a mass-based trading program requires that 

policymakers establish an approach for the initial distribution 

of allowances, historically referred to as “allowance 

allocation.” The EPA believes that states may be well positioned 

to design their own allowance distribution approach because they 

can take into account a wide range of considerations and tailor 

decisions to the particular characteristics and preferences of 

their state. We are proposingThe EPA proposes that states have 

the flexibility to determine their own approach for distributing 

allowances in the federal plan, through a process that is

detailed in section V.E. of this preamble. The EPA believes that 

states should have the opportunity to make decisions about 

allowance distribution and that they may have additional 

flexibility on approaches, including allowance auctions. The EPA 

is also proposing an allocation approach that we intend to use 

in the event we implement the federal plan in a state that does 

not choose to determine its own allowance-distribution approach.

The EPA is requesting comment on all of these, and any other, 

approaches to distribute allowances.

The initial allowance allocation approach that is based on 

historichistorical data does not affect the environmental 

results of the program or generation patterns; regardless of the 
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manner in which allowances are initially distributed, the finite 

total number of allowances limits allowable emissions across all 

affected EGUs. Allowance allocations also are not intended to

prescribe or suggest any unit-level compliance requirements nor

do they limit unit-level operational flexibility, because a 

mass-based trading program provides operators of affected EGUs 

with the flexibility to buy, sell, or bank allowances. Allowance 

allocation is simply a procedure by which allowances are 

distributed into the marketplace so that they may be available 

for affected EGUs to acquire as desired to authorize emissions 

under the program. However, because these allowances are finite 

in number and thus a limited resource, they have value, and as a 

result, initial allowance allocations may raise issues of equity 

among recipients.

Thus the agency recognizes that its choice of allocation 

methodology is important from the perspective of distributional 

effects, and the importance of selecting an approach that is 

fair and reasonable in light of this consideration and the 

overall purpose of CAA section 111 informs the agency’s thinking 

in this proposal. We also invite comment on these 

considerations, and on any other factors or considerations which 

commenters believe should inform the allocation method.

The EPA believes that the most reasonable basis for an 
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initial allowance allocation procedure is an approach that uses 

historical data reported by the affected EGUs subject to the 

requirement to hold allowances under this program. This approach

relies on known data rather than future projections. The EPA 

believes this approach is preferable because any approach tied 

to future indicators (e.g., the expected future EGU-level 

pattern of emissions or the ultimate use of allowances) would 

depend on future outcomes that the EPA cannot project with

perfect certainty in advance. Basing allocation on 

historichistorical data is also consistent with the EPA’s 

approach to initial allowance allocation under previously 

established mass-based trading programs.

The EPA proposes to allocate most CO2 emission allowances to 

existing affected EGUs in each state covered by a final massbased trading federal plan, with set-asides for a portion of 

allowances (discussed in more detail below). For each compliance

period, the agency would distribute CO2 allowances in each 

covered state in the amount of the state’s CO2 “mass goal” (i.e.,

the state’s CO2 statewide mass-based emission goal as promulgated 

in the Clean Power Plan EGs) for that compliance period. For 

example, if a compliance period is three3 years long, the EPA 

would aggregate and distribute allowances for all three3 years 

at the same time. The agency is not proposing to allocate
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allowances to new EGUs, which do not have a compliance 

obligation under this proposed federal plan.

Within each covered state, For each year of the program,

the agency proposes to allocate most of the allowances directly 

to affected EGUs using a historic-generation based approach. The 

EPA is also proposing three set-asides of allowances, which are 

detailed below.

Although the EPA cannot anticipate the future EGU-level 

pattern of emissions, it is possible to consider potential 

future emission patterns at the source subcategory level. In 

developing the Clean Power Plan EGs, the agency conducted 

analysis of emission reduction potential in the two affected EGU 

source subcategories, i.e., electric utility steam generating 

units (steam generating units) and NGCC units. With that 

analysis as a basis, the EPA is requesting comment on an 

alternative allocation approach that would first divide the 

total number of allowances from each state’s mass goal into

source subcategories based on analysis done in developing the 

source category-specific CO2 emissions performance rates 

promulgated in the EGs and then allocate to affected EGUs within 

each category based on shares of historic generation. This 

alternative is described later in this section.

The EPA recognizes that states may prefer different 
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approaches to distribute CO2 allowances from the EPA’s approach

and that there may be advantages in having states tailor and 

apply their own allocation approach. Therefore, the agency is 

proposing that a state may choose to replace the federal-plan 

allowance-distribution provisions with its own allowancedistribution provisions, using any approach to distribute 

allowances that the state chooses, including methods that the 

EPA is not proposing here, provided that the state’s approach 

addresses emissions leakage as detailed in section V.E, and 

includes a Clean Energy Incentive Program. The proposed 

requirements for addressing leakage, as well as detailed later 

inhow the EPA proposes to implement the Clean Energy Incentive

Program for the mass-based federal plan, are detailed in 

sections V.E and V.D.4 of this sectionpreamble, respectively.94. 

The EPA proposes that a state could choose its own method for 

distributing allowances for any compliance period including the 

first period that would commence in 2022. The proposed process 

for a state to replace federal-plan allowance-distribution 

provisions with its own allowance-distribution provisions is 

 

94 As detailed in section V.E in this preamble, a state that chooses to determine 

its own allowance-distribution approach under the proposed federal plan may do 

so through its allocation strategy (such as the set-aside approaches in section 

V.D.3) or may make a justification regarding leakage as detailed in section 

V.E.
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detailed in section V.E of this preamble.

The following sections discuss and request comment on the 

EPA’s proposed approach to allocate CO2 allowances to affected 

EGUs based on shares of historic generation, the proposed timing 

of allowance recordation, three proposed allowance set-asides, 

allocations to units that change status, and the proposed 

approach for states to replace federal-plan allocation

provisions with their own allowance-distribution approaches. In 

addition, we request comment on alternative allowance 

distribution approaches – such as auctioning or allocations to 

load-serving entities – that the EPA or states might adopt. The 

EPA requests comment on all of these aspects of allowance 

distribution.

1. Proposed Allocation Approach and Alternatives

The EPA proposes to allocate most of the CO2 allowances in 

the mass-based trading program to affected EGUs based on 

historic generation (output) data. The EPA also proposes three 

allowance set-asides. The first would set aside a portion of 

allowances in each state from the first compliance period only; 

this set-aside is for a proposed Clean Energy Incentive Program 

that is detailed in section V.D.4. of this preamble. The second 

would set aside a portion of allowances in each compliance 

period except for the first period (; the size of this set-aside 
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would vary by state as detailed in section V.D.3); EPA 

wouldproposes to distribute allowances from this set-aside to 

affected EGUs via an updating output-based approach. as detailed 

in section V.D.3 of this preamble). The third would set aside

five percent of allowances in each state, in all compliance 

periods, to be distributed to renewable energyRE projects as 

detailed in section V.D.3 of this preamble. In summary, the 

proposed set-asides include:

(1) Clean Energy Incentive Program. This set-aside would be 

of first compliance period allowances only. 

(2) Output-based allocation set-aside. This set-aside would 

start in the second compliance period and continue for each 

compliance period.

(3) Renewable energy set-aside. This set-aside would be 

implemented in all compliance periods.

This section describes the proposed historic-generationbased approach that the agency would use to allocate all 

allowances except for the set-aside allowances. The EPA is 

proposing affected-EGU-level allocations (based on available 

data) in every state. Further detail on this proposed allocation 

approach is provided in the Allowance Allocation Proposed Rule 

TSD in the docket. The affected-EGU-level allocations resulting 

from this proposed historic-generation-based approach are 
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provided in the docket in an appendix to the TSD. The agency 

requests comment on the proposed historic-generation based 

allocation approach and on other allocation approaches.

The EPA proposes to allocate the historic-generation-based 

portion of the allowances (i.e., the mass goal minus the setasides95) to individual affected EGUs based on each affected 

EGU’s share of the state’s historic generation, using 2010 

through 2012 data. The calculation steps for this proposed 

historic-generation–based allocation approach are as follows:

1. For each unit in the list of likely affected EGUs in each 

state, identify annual net generation values for the 

historic period of 2010 through 2012 (reflecting affectedEGU-specific generation assumptions incorporated in the 

data adjustments, e.g., assumed capacity factor for “under 

construction” units). For a year for which an affected EGU

has no generation data (e.g., a year before the year when a 

unit started operating), assign the affected EGU a value of 

 

95 In the first compliance period this would be the mass goal minus 

the Clean Energy Incentive Program set-aside and the RE set-aside. 

In all other compliance periods this would be the mass goal minus 

the output-based allocation set-aside and the RE set-aside.
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zero.96 (See step 2, below, for how zero values would be 

treated in the calculations.)

The EPA proposes to use a three3-year historic period

(i.e., 2010 through 2012) to reflect unit-level operations

over time. In the Clean Power Plan EGs, the EPA identified 

a reasonable basis for using aggregate data at the regional 

level largely based on the most recent data year (in that 

case, 2012) to inform the establishment of category-wide 

EGs (as opposed to individual, unit-specific parameters). 

As a distinct matter, in this context the EPA is 

considering data at the unit level to inform unit-specific 

initial allowance allocations; notwithstanding that these 

allowance allocations do not impose any unit-level 

compliance requirements in and of themselves, the EPA finds 

it reasonable to consider a multi-year data period to 

 

96 The EPA proposes that for affected EGUs that were under 

construction and began operation during 2012 or after 2012 (and 

thus don’t have a full year of generation data from the 2010 

through 2012 period), the allocation calculations be based on the 

same 2012 generation estimate as the agency used in the Clean Power 

Plan EGs for the goal-setting calculations. That is, the EPA 

proposes to estimate 2012 generation for such units based on a 

unit’s net summer capacity and assuming a 55 percent capacity 

factor for gas units and a 60 percent capacity factor for steam 

units.
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inform unit-level initial allocations in order to consider 

a broader range of unit-specific operations over time.

2. Determine each affected EGU’s average generation value by 

averaging all (non-zero) 2010 through 2012 annual 

generation values for the unit. The proposed approach would 

use only non-zero values in calculating a unit’s average 

generation. For example, if generation data for a unit were 

available for only 2011 and 2012 then the EPA would only 

use the 2011 and 2012 values to determine the unit’s 

unadjusted average generation value. The EPA included 

generation from all units in the historic data set in the 

proposed allowance calculations and calculated allowances 

for all such units; the agency requests comment on the 

treatment of generation from and allocations to units that 

operated in the historic data set but retire before the 

start of the program. 

3. In each state, sum the average generation values from all 

affected EGUs to obtain that state’s “total average 

historic generation.”

4. Divide each affected EGU’s average generation value by the 

state’s total average historic generation to determine that 
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affected EGU’s share of the state’s total average historic

generation.

5. Multiply each affected EGU’s share of the state’s total 

average historic generation by the historic-generationallocation portion of the state’s mass goal (i.e., the 

state’s mass goal minus the set-asides) to determine that 

affected EGU’s allocation.

The agency believes that this proposed historic-generationbased allocation approach is a reasonable approach for several 

reasons:

• The agency believes that the proposed historicgeneration-based approach maximizes transparency and 

clarity of allowance allocations. The EPA has placed in 

the docket the historic generation data and the 

calculations used to determine the proposed affected-EGUlevel allocations. The agency also placed the proposed 

affected-EGU-level allocations, resulting from these 

calculations, into the docket. These calculations can be 

relatively easily replicated.

• To calculate allocations, the EPA proposes to use 

historic affected-EGU-level net generation data compiled 

using a methodology similar to the Emissions & Generation 
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Resource Integrated Database (eGRID) methodology. The 

proposed calculation approach is described further below 

and in the Allowance Allocation Proposed Rule TSD in the 

docket. The historic-data methodology is described in the 

&&&CO2 Emission Performance Rate and Goal Computation TSD 

for CPP Final Rule. The majority of the generation-unitlevel data in this approach are from reports that 

emissions sources submit to the EPA under 40 CFR part 75 

and to the Energy Information Administration (EIA) on 

forms EIA-860 and EIA-923. The EPA believes these are the 

best data available to the agency at the time of this 

proposed rule for calculating affected-EGU-level 

allocations.

• Allocating based on historic data (as opposed to data not 

yet reported) allows for the distribution of allowances 

prior to the start of the program, which can facilitate

compliance planning.

The proposed approach is transparent, based on reliable 

data, and, like the approaches used in the NOX SIP Call, Acid 

Rain Programthe ARP, and Cross-State Air Pollution RuleCSAPR, 

based on historic data. For all these reasons, the agency 

believes that it is appropriate to use a historic-generation-
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based allocation methodology in this proposed rule. The EPA also 

requests comment on a historic-data approach based on historic 

emissions.

The proposed historic-data-based allocations approach would 

not generally affect the ultimate pattern of generation across

individual power plants, as compared to other methods of 

allocation. The combination of plants, and their contributing 

generation, that will be used to meet a particular demand for 

electric power will be based on the relative efficiency (cost of 

production) of available plants. The relevant measure of this 

efficiency is the marginal cost of generation, which for a 

particular power plant would be the sum of the cost of 

additional fuel to generate an additional MWh, additional 

maintenance costs to increase output by an additional MWh, and 

costs associated with the additional emissions that result from 

generating an additional MWh. In a mass-based trading program, 

additional emissions must be covered by additional allowances, 

so the cost of emitting is the price of the allowances that must 

be consumed to authorize those emissions. These emissionsrelated costs of electricity production are the same regardless 

of whether the allowances used to cover those emissions were 

initially allocated to the user or whether they were acquired 

subsequently in the marketplace.
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The same concept applies to any other cost of electricity 

production. For example, a coal-fired electric generating 

unitEGUs operator would account for the cost of consuming coal 

to produce generation whether or not the coal was discovered 

already on-site, given to the unit at “no charge”, or purchased 

from the marketplace; in all cases, the combustion of that coal 

consumes its value (i.e., it can no longer be sold). Similarly, 

the approach taken to distribute allowances does not affect the 

cost accounting for emissions at units because the use of any 

tradable allowance has an opportunity cost – a firm loses the 

opportunity of selling an unneeded allowance when it emits an 

additional ton. Because a firm loses the opportunity of selling 

an unneeded allowance when it emits an additional ton, even the 

emission of a ton covered by a “free” allowance causes the 

generator to incur the cost of emissions based on the market 

price of allowances the owner must forgo by emitting that ton 

and using that allowance. 

The proposed historic-data based allocation approach would 

not be expected to have any effect on freely competitive 

electricity markets, because the marginal cost of emitting under 

the mass-based trading program is determined by the level of the 

overarching mass goals and is not affected by the distribution 

of the underlying allowances. This marginal cost of emitting is 
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what will inform prices, outputs, and competition among power 

plants. While cost-of-service markets are structured differently 

from competitive markets, the regulated utility still makes the 

dispatch decision on the basis of marginal costs among the units 

in its fleet, which is not affected by the amount of allowances 

that any particular unit in that fleet was initially allocated

(assuming a competitive allowance market).

The EPA recognizes that some stakeholders are concerned 

about the potential future distribution of emissions at the 

facility level, and possible effects on communities. However, 

for the reasons discussed in the above paragraphs, allowance 

allocations that do not change based on future activity (such as 

allocations under the proposed historic-generation based 

approach) do not affect the distribution of emissions under the 

program. This proposed rule is expected to achieve significant 

emission reductions across the electric power sector; see 

section IX of this preamble for discussion of anticipated broad 

benefits to communities.

In addition to the proposed historic-data-based allocations 

approach, the EPA also requests comment on other allocation 

approaches. One alternative approach on which the agency 

requests comment is similar to the proposed approach in that it 

allocates allowances based on historic generation. However, this 
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alternative approach would divide the total number of allowances 

from a state’s mass goal (minus the set-asides) into affected 

EGU source categories – based on analysis done in developing the 

source category-specific CO2 emissions performance rates 

promulgated in the Clean Power Plan EGs – before determining 

unit-level allocations. The EPA requests comment on this 

alternative approach because dividing the allowances in a state 

by source category in this manner may result in an initial 

distribution of allowances that would be closer at the sourcecategory level to the future category-level pattern of 

emissions, and thus to allowances ultimately used, than the 

proposed approach. To the extent that this category-level 

division of allowances is a reasonable proxy for the future 

category-level emissions pattern under the program, this 

approach may reduce wealth transfer between parties that occurs 

as a consequence of a less-anticipatory initial allocation 

procedure. The EPA cannot observe in advance the future 

affected-EGU-level pattern of emissions.

In this alternative approach, for each state the EPA would 

multiply historic steam-generating-unit generation by the steamgenerating-unit source category-specific CO2 emissions 

performance rate, and multiply historic NGCC-unit generation by 

the NGCC-unit source category-specific CO2 emissions performance 
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rate. The EPA would do these calculations for each of the 

compliance periods in the Interim Period using the glide path 

interim performance rates, and for the Final Period using the 

final performance rates. These performance rates are shown in 

Tables &&& and &&&Table 6 in section IV.B of this preamble, 

above. The EPA established the source category-specific 

emissions performance rates in the Clean Power Plan EGs (see 

section VI inof the final EGs); these rates are not within the 

scope of this proposed federal plan rulemaking. Next, for each 

compliance period the EPA would split the total number of 

allowances from the state’s mass goal (minus the set-asides) 

into affected-EGU source categories in proportion to the values 

resulting from the above calculation. The EPA would then 

allocate the steam–generating-unit portion of the allowances to 

individual steam generating unitsSGUs using the same historicgeneration based approach described above, and would also 

allocate the NGCC-unit portion of the allowances to individual 

NGCC units using the historic-generation based approach.

The EPA notes that there are multiple approaches that 

policymakers may use to distribute allowances, beyond the 

proposed or alternative allocation approaches we included in 

this proposed rule. Examples of other allocation approaches 

include allocating based on historic heat input (fuel) or 
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historic emissions data, rather than historic generation data.

The choice to use historic data for allocation (e.g.,

generation, heat input, or emissions) means that the

distribution of allowance value will be based on past behavior. 

For example, allocations based on historic emissions would 

benefit those that have historically been the largest emitters, 

whereas allocations based on historic heat input or generation 

(output) would benefit those that have historically used the 

most fuel or generated the most electricity.97 Alternatively, 

allocations could be distributed based on projected or observed

future activity (e.g., generation, heat input, or emissions).

The proposed and alternative allocation approaches would 

determine most of the allocations before the start of the 

program. Other potential allocation approaches would change 

allocations for future compliance periods based on future 

activity – referred to as “updating” allocations. This proposed 

rule includes an updating-allocation component, as we are 

proposing to set aside a portion of the allowances in each state 

for distribution using an updating output-based approach as 

detailed in section V.D.3. of this preamble. The EPA requests 

comment on the use of other updating allocation approaches.

 

97 Tools of the Trade, A Guide to Designing and Operating a Cap and 

Trade Program for Pollution Control, EPA, 2003.
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Another allowance allocation approach that could minimize 

the difference between the initial allowance allocation and the 

ultimate distributional pattern of allowance use for compliance 

is to conduct an auction, a process whose express intent is to 

align the allocation of a scarce good (in this case, the limited 

authorization to emit CO2) with the parties most willing to pay 

for its use. Many ascribe benefits, in terms of economic 

efficiency, to the use of auctioning as a means of allocating 

allowances. The EPA notes that some states (e.g., RGGI 

participating states) have used auctions to distribute 

allowances and have used auction revenues for a variety of 

purposes, including the implementation of demand-side energy 

efficiencyEE measures intended to help reduce electricity rate 

impacts and overall program costs, as well as targeted 

investments in low-income communities. The EPA believes that if 

it conducted allowance auctions, any revenue from such auctions 

received by the agency must be deposited in the U.S. Treasury 

under federal law.98 As a result, the EPA notes that states 

implementing state plans may have greater flexibility than the 

 

98 The EPA believes authority to conduct auctions is located in CAA 

section 111 alone, as well as by its reference to CAA section 

110(c) FIPs. The statutory definition of a FIP authorizes 

“techniques (including economic incentives, such as marketable 

permits or auctions of emissions allowances).” 42 U.S.C. 7602(y).
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federal government would to direct auction funds for particular 

activities. The agency requests comment on the idea of 

auctioning all, or a portion of, each state’s allowances in the 

proposed federal plan, on how much of each state’s allowances to 

auction if not the entire amount, on the frequency (e.g., yearly 

or every few years), design of auctions (e.g., spot or advance; 

first, second-price or other) and who may participate in the 

auction.

The EPA requests comment on an alternative approach, which 

is allocating a portion of the allowances to load-serving 

entities (LSEs) rather than to affected EGUs. LSEs are the 

entities responsible for delivering power to retail consumers. 

Allocation to LSEs can help mitigate bill impacts on 

electricity consumers when applied in concert with certain 

additional design features. In particular, if LSEs commit and/or 

are required to pass through to ratepayers the value from their 

selling of the allocated allowances, this approach can mitigate 

the impact of electricity bill increases on consumers that might 

otherwise result from application of the federal plan. As 

described in the Allowance Allocation TSD, this type of approach 

can also help to avoid or mitigate the potential for windfall 

profits for affected EGUs. The EPA could apply this approach by 

conditioning the receipt of allowances by LSEs on the pass 
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through to consumers of any allowance value if necessary.

The EPA requests comment on the design and utility of 

allocating allowances to LSEs to help mitigate electricity price 

impacts. In particular, the EPA requests comment on options to 

establish conditions requiring pass through of allowance value 

and verification of such pass-through, whether it would be 

appropriate to identify any conditions related to equitable 

distribution of allowance value among ratepayer categories, as 

well as the EPA’s legal authority to apply any such conditions.

The EPA requests comment on the additional design aspects 

of any potential allocation to LSEs, including but not limited 

to the following questions: In particular, what metric should 

provide the basis for LSE allocation, e.g., electricity demand

served by the LSE, population served by the LSE, emissions 

associated with generation serving the LSE, or some other 

metric. If emissions are used as the basis for such allocation, 

what approach should be taken: on a historic basis or a 

continually updated basis, on the basis of estimated emissions 

for the relevant region or some other basis, and using what data 

to calculate such emissions. Also, the EPA requests comment on 

the form by which LSEs may distribute the allowance value to 

rate-payers, e.g. as a fixed amount, through reduced rates, etc. 

Finally, the EPA requests comment on what share of the total 
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number of allowances should be distributed to LSEs and what 

monitoring and reporting requirements may be necessary to 

support an effective program.

The EPA requests comment on the proposed historicgeneration based allocation approach, the alternative approach 

that divides total allowances from a mass goal into source 

subcategories before allocating to individual affected EGUs

within each source category based on historic generation, and on 

the other alternative approaches described in this section. The 

EPA also requests comment on allocating allowances to all 

generation in a state (including non-emitting generation) using 

a historic-generation based approach. The agency also requests 

comment on the proposed allowance set-asides, which are detailed 

below. The agency requests comment on allocation approaches that 

may minimize the impact of this proposed rule on small entities. 

The EPA also requests comment on any other approaches to 

distribute allowances. Finally, The agency notes that we propose 

to provide that any state may choose to replace the federal-plan 

allocation provisions with an allocation approach of its 

choosing as discussed below. Finally, with regard to alternative 

allocation methodologies (either those specifically mentioned in 

this proposal or other allocation methodologies), the EPA 

requests comment on how those alternatives would satisfy the 
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requirement that in a mass-based program where new sources are 

not included as part of the program, the allocation methodology 

must address leakage to new fossil-fuel-fired sources.

2. Timing of Allowance Recordation

The proposed historic-data-based allocation approach –

which the EPA proposes to use to allocate all of the allowances 

in each state except for the set-aside allowances – is a onetime determination that is not updated. The allocations 

resulting from this approach would be determined prior to the 

start of the program. The EPA proposes to record the historicdata based allowances for each compliance period in source 

accounts prior to the start of each compliance period, and to 

record allowances for one compliance period at a time. Recording 

allowances prior to the start of a compliance period provides 

certainty to affected EGUs of their allocations in advance of 

when the allowances are needed for compliance and can facilitate 

long-term planning. Recording allowances for one compliance 

period at a time provides flexibility for a state to replace the 

federal plan with its own plan in a timely way. As discussed in 

section V.F of this preamble, the EPA proposes to allow a state 

to replace the federal plan with its own approved state plan,

for a compliance period for which allowances have not yet been 

recorded (the proposed schedule for allowance recordation is 
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detailed below). The EPA also proposes that a state could choose 

to replace the federal-plan allocations to its affected EGUs 

(and other entities) with its own allocations approach, for a 

compliance period for which allowances have not yet been 

recorded as detailed in section V.E of this preamble.

The agency proposes to record allowances for the mass-based 

trading program in accounts of affected EGUs seven months prior 

to the start of each compliance period. For example, if 

compliance periods are three3 years long and the first 

compliance period comprises the years 2022, 2023, and 2024, the 

EPA would record allowances for 2022, 2023, and 2024 by June 1, 

2021. The EPA requests comment on the proposed approach of 

recording allowances seven7 months prior to the start of each 

compliance period, and on an alternative of recording allowances 

13 months prior to the start of each compliance period. See 

section V.D.3 of this preamble for timing of recordation of 

allowances from the proposed set-asides.

3. Allowance Set-asides to Address Leakage to New Sources

In addition to the general allocation method proposed 

above, the EPA is proposing two additional components of 

allowance allocation under a mass-based federal plan. These two 

set-asides are being proposed to satisfy the requirement in the 

final guidelines that mass-based plans demonstrate that they 
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have addressed the risk of leakage to new unaffected units, as 

specified below.99

The final emission guidelines, in Sec.VII.D,EGs specify 

leakage to be the concern of leakage, which is defined in 

section VII.D of the final EGs preamble as the potential of an 

alternative form of implementation (e.g., the rate-based and 

mass-based state goals) to spur increased emissions from new 

sources, beyond the emissions expected from new sources if 

existing EGUs were given create a larger incentive for affected 

EGUs to shift generation to new fossil fuel-fired EGUs relative 

to what would occur when the implementation of the BSER took the 

form of standards of performance in the form of incorporating 

the subcategory-specific emission performance rates.100 This 

section of the final guidelines also specifies how leakage must 

be addressed as part of an implementation of a mass-based goal 

as an expression of BSER. This is because a mass-based approach 

provides differing incentives to existing affected EGUs and new 

unaffected sources, unlike under a rate-based approach. This 

 

99 The EPA is also proposing a third set-aside, for a Clean Energy 

Incentive Program, which is detailed in section V.D.4 of this 

preamble, below.

100 Section VII.D of the final guidelines is incorporated by 

reference in this proposal.
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provides an increased potential for leakage under a mass-based 

approach, and thus states adopting mass-based plans must address 

leakage in order to assure the mass-based goal is equivalent to 

the mathematical expression of representing the BSER in CO2

emission performance rates. 

Therefore,.. The final guidelines requireEGs specified that 

jurisdictions implementing a mass-based plan approach make a 

demonstration that leakage has been addressed in their plan (See 

final guidelines Sec. VIII.J). The options for making that 

demonstration include: creating a mass limit that opts in new 

sources, implementing allocation strategiesapproaches must 

address leakage, because the form of the mass goals may 

ultimately impact the relative incentives to generate and emit 

at affected EGUs as opposed to shifting generation to new 

sources, with potential implications for whether the mass goal 

implements or is consistent with the BSER and overall emissions 

from the sector. These circumstances are much less likely to be 

present under a rate-based plan approach, where the form of the 

goal ensures sufficient incentive to affected existing EGUs to 

generate and thus avoid leakage, similar to the CO2 emission 

performance rates. By requiring mass-based plan components that 

address leakage, or justifyingthe final EGs ensure that mass 

goals are equivalent to the CO2 emission performance rates and 
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are thus an equivalent expression of the BSER. Section VII.D of 

the final EGs details the requirement for addressing leakage and

why leakageit is not a concern for the jurisdiction because of 

existing policy or unique characteristics.needed, and section

VIII.J of the final EGs specifies options for mass-based state 

plan components that address leakage. We are proposing, as part 

of the mass-based approach under the federal plan and model 

rule, to implement allowance allocation approaches to address 

leakage through the use of allocations strategies, specifically 

through the use of a combination ofestablishing an output-based 

allocation set-aside and a set-aside that encourages the 

installation of RE.

As noted in the EG, if a state were to adopt allowance 

set-aside provisions exactly as they are outlined in the 

finalizedthis model rule, they could once it is finalized, the 

requirement for that state plan to address leakage would be 

considered presumptively approvable.

Sec.Section VIII.J of the final guidelinesEGs provides a 

discussion of how set-asides can effectively address leakage in 

a mass-based plan approach, and that section in incorporated by 

reference in this section of the federal plan and model rule 

proposal.. That section of the final guidelinesEGs also 

describes why the allowance allocation alternative for 
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addressing leakage must be chosen for the federal plan and model 

rule proposal instead of the option to regulate new non-affected 

fossil fuel-fired EGUs. This is because the EPA does not have 

authority to extend regulation of and federal enforceability to 

new fossil fuel-fired sources under CAA section 111(d), and 

therefore we cannot include new sources under a federal massbased plan approach.

Set-asides can also be used to target and refine allowance 

allocation in order to achieve beneficial outcomes, for example 

ensuring program integrity and mitigating costs. The set-asides 

we are proposing – described in detail below - would establish a 

pool of allowances that would be allocated to affected EGUS or 

other entities, and would be allocated based upon different 

criteria in orderdesigned to support particular program goals, 

in particular addressingaddress leakage. 

These set-asides are essentially a type of “economic 

incentive” authorized by the CAA as a means of pollution 

prevention and control, and the expected benefits of this 

particular type of economic incentive to address leakage make it 

appropriate here.101 The EPA believes these set-aside programs 

 

101 In designing a federal plan under CAA section 111(d), the EPA 

recognizes its authority as being, in some sense, the same as that 
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are both authorized and consistent with the purpose of the Clean 

Power Plan under CAA section 111(d) and the specific 

requirements specified in the final guidelines. They do not have 

the effect of increasing the stringency of the federal plan,

because the overall budget of allowances (representing allowable 

emissions) remains the same. 

The EPA is aware of the successful use of set-asides and 

similar programs in other emissions trading programs. The 

following are examples of set-asides and similar programs used 

in other federal air quality rules, and in state-based GHG 

regulatory programs.

The EPA has previously established set-asides of emissions 

allowances in FIPs under CAA section 110 of the Clean Air Act..

For example, in the Cross State Air Pollution Rule (CSAPR),, the 

EPA used a 5 percent set-aside for new units, because we 

believed it was “important to have a small new unit set-aside in 

each state to cover new units within the budget that was set 

aside in order to address the state’s significant contribution 

and interference with maintenance.” (75 FR 45310; Aug. 2, 2010). 

This was important, in the EPA’s view, because it allowed for 

 

available under CAA section 110(c), where the use of economic 

incentives is authorized. See 42 USC 7602(y) (authorizing use of

“economic incentives” in FIPs). 
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growth in the electric utility sector consistent with the EPA’s 

modeling, where new units showed up in the modeling output as 

surrogate facilities representing potential new EGUs that come 

online in future years in response to demand increases or other 

market drivers.102 As between a choice of requiring these new 

units to purchase their allowance on the open market, versus 

being treated in the same manner as existing – and generally 

understood to be less efficient and more polluting – units, 

i.e., by being eligible to receive a freean initial allowance

allocation out of the new unit set-aside, the EPA chose the 

latter. 

As part of the Acid Rain ProgramARP under Title IV of the 

1990 CAA Amendments, Congress established a “conservation and 

renewable energy reserve” account. CAA section 404(f), 42 U.S.C. 

7651c(f). This is in essence a set-aside account of SO2

allowances which the regulated utilities could earn by 

undertaking “qualified energy conservation measures” and 

“qualified renewable energy” projects. The size of the reserve 

was set at 300,000 allowances, and utilities could earn one SO2

allowance for every 500 MWh of energy saved through DS-EE 

savings or RE generation. In the first years of the program, 

 

102 See also EPA, Allowance Allocation Final Rule TSD, EPA-HQ-OAR2009-0491, at 3-4 (June 2011).
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utilities received bonus allowances equivalent to close to 3,000 

tons of avoided SO2 emissions, while achieving co-benefits from

reductions in other pollutants, and, in the words of one 

industry representative, “creating a culture change where 

utilities are looking for opportunities everywhere.”103 The 

reserve program was nonetheless undersubscribed, and the EPA and 

other parties have learned from this case and made adjustments 

to similar programs to promote participation. This can be done 

through using alternate strategies for the MWh-to-allowance 

ratio, such as the pro rata distribution strategy proposed as 

part of the RE set-aside. This proposal also triesseeks to 

minimize the administrative burden associated with participation 

in thethis rule’s proposed set-asideasides.

In the NOX SIP Call, the EPA encouraged states to “consider 

including energy efficiency and renewables as a strategy in 

meeting their [emission] budgets. One way to achieve this goal 

is including a provision with a state’s NOx Budget Trading Rule 

that allocates a portion of a state’s trading program budget to 

implementers of energy efficiency and renewable energy projects 

that reduce energy-related NOx emissions during the ozone 

season.” See 63 FR 57356, 57438 (Oct. 27, 1998). A number of 

 

103 U.S. EPA, Acid Rain Program, Conservation and Renewable Energy 

Reserve, EPA 430-R-94-010 (Nov. 1994).
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states created RE and demand-side EE set-asides in their SIPs in 

response, and later, for the implementation of CAIR. A 

“roundtable” meeting with 25 states in 2006 indicated that 

states that had established these programs were generally having 

success with them, and provided a forum for exchanges of ideas 

on how to handle a variety of implementation issues, such as 

over- and under-subscription, application issues, compliance and 

verification, the appropriate size of a set-aside account, how 

to garner public input on which projects are selected, and other 

issues.104 In general, the EPA believes its experience and those 

of the states with these set-aside programs support the view 

that they are an effective means to spur clean energy projects, 

which in turn we believe can help to reduce the risk of leakage 

in this instance.105

 

104 U.S. EPA, State Clean Energy-Environment Technical Forum 

Roundtable on State NOx Allowance EE/RE Set Aside Programs, Call 

Summary (June 6, 2006), available at 

http://www.epa.gov/statelocalclimate/documents/pdf/summary_paper_nox_allowan

ce_6-6-2006.pdf. 

105 The agency has extensive experience in the design and 

establishment of set-aside programs. See, e.g., Guidance on 

Establishing an Energy Efficiency and Renewable Energy (EE/RE) 

Set-Aside in the NOx Budget Trading Program (March 1999), available 

at http://www.epa.gov/statelocalclimate/documents/pdf/ee-re_set-asides_vol1.pdf; Creating an 

EE and RE Set-aside in the NOx Budget Trading Program: Designing 
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Below, the EPA describes two potential allowance setasides. First, the EPA proposes a set-aside for allowances 

distributed to existing NGCC units based on output (i.e.,

output-based allocation) to mitigate emission leakage to new 

sources, with the ancillary advantage of further addressing the 

potential for increased emissions due to movement of generation 

to existing sources in neighboring states that adopt rate-based 

approaches, though the potential for that that is minimized by 

the incentives present under a rate-based plan.. Second, the EPA 

proposes a set-aside for electricity generation from qualifying 

renewables. This set-aside also addresses the potential for 

leakage to new sources, as increased RE capacity can serve 

electricity demand in place of new sources. The EPA also 

solicits comment on other set-aside options that could support 

the goals of the program, in particular addressingaddress

leakage, including a set-aside that provides an incentive for 

demand-side EE. The EPA seeks comment on all aspects of the set-

 

the Administrative and Quantitative Elements (April 2000), 

available at http://www.epa.gov/statelocalclimate/documents/pdf/ee-re_set-asides_vol2.pdf; 

Creating an EE and RE Set-aside in the NOx Budget Trading 

Program: Evaluation, Measurement, and Verification of Electricity 

Savings for Determining Emission Reductions from Energy Efficiency 

and Renewable Energy Actions (July 2007), available at 

http://www.epa.gov/statelocalclimate/documents/pdf/ee-re_set-asides_vol3.pdf.
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aside options specified in this section. This includes the 

inclusion of a set-aside, the method for allocation of 

allowances to set-asides, the size of the set-asides, the 

requirements for the process of distribution, eligibility 

requirements for receiving set-aside allowances, the proposed 

process for redistribution of undistributed allowances from each 

set-aside, and any other appropriate set-asides.

a. Set-asides for Output-based Allocation

The EPA is proposing a set-aside approach referred to as 

output-based allocation, which provides targeted allocations of 

a limited portion of allowances to existing NGCC units as a 

means of mitigating leakage. The EPA believes that this proposed 

set-aside would help ensure the environmental integrity of a 

mass-based plan, and could potentially reduce costs as well as 

address incentives for generation to shift away from EGUs 

covered under mass-based plans to new unaffected EGUs. We seek 

comment on all aspects of this proposal and its underlying 

rationale.

Under the output-based allocation approach we are 

proposing, somebeginning with the second compliance period, a 

portion of the total allowances within each mass-based federal 

plan state arewould be allocated to existing NGCC units based, 

in part, on their level of electricity generation in a recent 
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period. The allocation to an eligible EGU is not fixed, but 

instead depends on its generation.the previous compliance

period. Each eligible EGU would get a larger allowance 

allocation from this set-aside if it generates more, such that 

owner/operators of eligible EGUs will have an incentive to 

generate more in order to receive more allowances, making them 

more competitive than they would be without the set-aside..

Because the total number of allowances is limited, this 

allocation approach will not exceed the overall emission goal;.

Instead, it merely modifies the distribution of allowances in a 

manner designed to mitigate emission leakage.

Output-based allocation provides an incentive for eligible

EGUs in mass-based states to increase their generation in order

to increase their allocation of allowances. This incentive helps 

align the generation incentives for eligible EGUs in mass-based 

states with new emitting EGUs within mass-based states that are 

not subject to thea mass-based limits as well as analogous EGUs 

in other states covered by emission rate limitslimit, mitigating

emissions leakage. The EPA also solicits comment on another 

potential ancillary benefit of this set-aside: mitigating

electricity price impacts associated with the proposed federal 

plan. Output-based allocation lowers the marginal production 

cost of eligible EGUs. Therefore, if these EGUs influence 
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electricity prices, the reduction in their production costs will 

place downward pressure on the electricity price. In the 

specific situation where eligible EGUs are in cost-of-service 

regions, the effect on electricity prices would depend on the 

relative cost of producing electricity from these EGUs relative 

to the cost of procuring power from EGUs subject to emission 

rate standards. 

It is important that the output-based allocation approach 

be designed to avoid unintended consequences. In particular, the

design should avoid, to the extent possible, reduction in 

incentives to invest in new zero- or low-emitting generation as 

a result of the downward pressure the allocation approach may 

place on electricity prices. This is also why an RE set-aside is 

a useful complement to the output-based allocation set-aside.

Furthermore, providing too strong a generation incentive to

affected EGUs eligible for the set-aside could increase total 

electricity production costs. Specifically, if applied too 

strongly, output-based allocation can go beyond the alignment of 

incentives across similar EGUs and lead to undesirable 

differences in incentives in the other direction. For example,

if eligible affected EGUs receive too large a number of 

allowances for each MWh of generation this could incentivize
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generation that is high cost, exclusive of the cost associated 

with obtaining the mass-based emission limit, and disincentivize

lower-cost generation subject to emission rate standards. This 

could raise the total cost of achieving overall emission levels

with relatively little environmental benefit. The output-based 

allocation set-aside should be designed to address these

economic concerns. 

The EPA accordingly solicitsis inviting comment on key 

parameters for the appropriate design of the output-based 

allocation approach used for this proposed set-aside. Key 

parameters to be identified under the output-based allocation

approach include which affected EGUs receive the allocation, the 

vintage for allowancestiming of the set-aside’s allocation 

procedure, the allocation rate(s), and the size of the setaside. The EPA solicitsalso invites comment on what other key

parameters may be relevant for design of an appropriate outputbased set-aside.

The EPA first solicits comment on which EGUs should be 

eligible to receive output-based allocation from the set-aside. 

The EPA proposes that only NGCC units subject to the final 

emissions guidelinesEGs receive output-based allocation from the 

set-aside, subject to limitations described below. The EPA 

recognizes that performance of output-based allocation may be 
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improved by targeting which units receive this additional 

incentive. In particular, this approach can most effectively 

address emission leakage if targeted to those affected EGUs 

subject to a mass goal that face the greatest difference in 

their incentive to generate relative to otherwise similar EGUs 

that are not subject to emission rate standards.a mass goal. As 

noted in the discussion of the allocation rate below, new 

combustion turbines (i.e., NGCC units and simple cycle 

combustion turbines) would be expected to generate more absent 

this set-aside. Therefore, the difference in generation 

incentives between affected stationary combustion turbines 

undersubject to a mass-based implementation goal and otherwise 

similar new stationary combustion turbines that are not subject 

to the 111(b) standardsa mass goal is likely one of the most 

salient deviations in production incentives to address.

As discussed further below, under this proposal other 

affected EGUs would not receive output-based allocations from 

this set-aside. Below we also request comment on whether sources 

other than NGCC units subject to the emissions guidelines should 

be eligible for output-based allocations under this set-aside. 

The EPA also proposes that this approach be targeted 

towards marginal generation by providing allocations under this 

set-aside only to eligible EGUs that exceed a certain average 
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capacity factor over the compliance period, and only for the 

portion of their generation that exceeds the specified capacity 

factor. The allocation rate would only apply above a particular 

average capacity factor because it is intended to incentivize 

marginal generation and not generation that would have otherwise 

occurred absent the output-based allocation from the set-aside. 

Under this approach, eligible affected EGUs would receive no 

allowances from this set-aside for generation below this average 

capacity factor (although all affected EGUs will still receive 

allowances through the historic-generation-based approach 

detailed above). This approach avoids incentivizing production 

at lower levels of generation from an eligible source, and 

therefore avoids discouraging a relatively inefficient or 

infrequently used EGU from retiring.106 The EPA proposes an 

approach under which each existing NGCC that is eligible for the 

set-aside receive output-based allocation at the allocation rate 

 

106 As discussed below, if a source would no longer receive 

allowance allocations after it retires it would be discouraged 

from retiring, which may increase total production costs. The logic 

for not providing output-based allocations to sources with low 

capacity-factors is the same, although the strength of the 

incentive to not retire is lower for output-based allocation than 

it is when the entire allocation to the source may be forfeit 

through retirement.
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only if its average capacity factor in the compliance period is 

above 50 percent on a net-basis. Furthermore, we propose that 

each eligible EGU receives allowances at the allocation rate for 

all generation above an average capacity factor of 50 percent. 

That is, there would be no “maximum” average capacity factor 

above which output-based allocations are not earned by an EGU

eligible to receive them.107 This is to maintain the marginal 

incentive to generate from the affected EGU. (The total number 

of allowances available in the set-aside is limited, however, as 

described below.) The EPA requests comment on implications of 

this approach for the operation and efficiency of electricity 

markets.

The EPA also solicits comment on selection of a source of 

allowances that is a specific vintage for allocation. This key 

parameter determines which compliance period’s allocation is 

distributed based, in part, on current period generation. 

Alternatives include the current compliance period’s allocation, 

which is the period in which the eligible generation occurs, and 

a future compliance period’s allocation. If allowances are 

allocated from a future period’s allocation, affected EGUs can 

receive additional allowances in a given future period, based on 

 

107 Effectively, the allocation rate of output-based allocation is 

zero up until this average capacity factor. 
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their additional generation in the current compliance period.

Both approaches create an incentive to increase generation 

in the current compliance period to secure additional 

allowances; the difference is in when those allowances may be 

used. Allocating current compliance period allowances based on 

current year generation may create uncertainty in that affected 

EGUs may not know if they will be allocated sufficient 

allowances to cover their emissions or will have to buy 

allowances, because their total allocation will not be fixed 

until the end of the period when their cumulative generation is 

known. Therefore, an advantage of allocating allowances from a 

future compliance period is that affected EGUs will know ex-ante 

how many allowances they will be allocated in a given period. 

However, if there is an expectation that the federal plan will 

be replaced by a state plan in the future compliance period, the 

incentive to respond to output-based allocations is potentially 

diminished. The longer the lag between the eligible generation 

and the output-based allocation, the greater the potential for 

uncertainty to lower the incentive associated with output-based 

allocation. At the same time, the ultimate effect of outputbased allocation timing will also depend on expectations about 

future allowance prices relative to current prices and the 

degree to which the banking of allowances is permitted. 
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Weighing these observations, the EPA proposes allocating 

allowances based on generation from eligible EGUs in the 

preceding compliance period. For example, the EPA would 

calculate set-aside allowances for the second compliance period 

(2025 through 2027) based on data from 2022 through 2024. In the 

first compliance period of the federal plan, allowances 

allocated to affected EGUs would be distributed per the 

historic-generation-based approach described above (with no 

further adjustment). The EPA also requests comment on other 

approaches to selecting a vintage (or vintages) for allocating 

allowances for an output-based allocation set-aside.

The EPA also requests comment on extending output-based 

allocation from this set aside to affected SGUs. Output-based 

allocation for SGUs may increase generation subject to the mass 

limit, leading to reduced generation and emissions from new 

emitting sources. However, the EPA does not propose this 

approach because it is not as effective as output-based 

allocation to NGCC units. This is because output-based 

allocation to SGUs would incentivize generation from relatively 

high-emitting EGUs, which would likely increase allowance prices 

as other emission reductions are made to respect the overarching 

mass limit. This approach would thus strongly counteract the 

intended effect of lowering the production cost from sources 
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subject to the proposed mass-based federal plan (compared to 

emitting sources not subject to the plan). The EPA also requests 

comment on extending output-based allocation from this set-aside 

to zero-emitting generators (including both renewable and 

nuclear generation), and how the design of the OBA set-aside for 

such generators would differ relative to the NGCC approach 

(e.g., the amount of allowances earned per MWh, the capacityfactor threshold, the size of the total set-aside).

The EPA also proposes that this approach be targeted 

towards marginal generation that may not have otherwise occurred 

absent this set-aside, by providing allocations under this setaside only to eligible EGUs that exceed a 50 percent capacity 

factor on a net basis over the compliance period, and only for 

the portion of their generation that exceeds that capacity 

factor.108

The EPA also solicits comment on the timing of the OBA setaside’s allocation procedure, which involves the relationship 

between the time at which eligible generation occurs and the

vintage year(s) of the allowances allocated from this set-aside 

to recognize that generation. The EPA is proposing a lagged 

accounting procedure for this set-aside, where eligible 

 

108 Effectively, the allocation rate (defined below) of outputbased allocation is zero up until this average capacity factor. 
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generation that occurs during a given compliance period would 

receive allowances through this set-aside taken from vintage 

years in the subsequent compliance period. In keeping with this 

lagged accounting procedure, the EPA is proposing not to reserve 

any allowances of vintage years during the first compliance 

period (2022-2024) for allocation through this set-aside; 

eligible generation that occurs during the first compliance 

period would be recognized through this set-aside with 

allowances of vintage years from the second compliance period 

(2025-2027).

The EPA is proposing this lagged accounting procedure 

because the amount and location of eligible generation in any 

given compliance period remains uncertain until the compliance 

period has ended and the relevant data has been reported and 

verified. Without this lagged accounting procedure, the EPA 

would have to withhold an amount of allowances for this setaside from certain vintage years even as the corresponding 

compliance period was already underway. Given the size of this 

proposed OBA set-aside in certain states, the EPA believes it 

would be more advantageous for affected EGUs to know in advance

how many allowances they will be allocated in a given period, 
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inclusive of allowances allocated through this OBA set-aside.109

The EPA requests comment on options for the allocation rate 

under this approach. The allocation rate is the emissionsequivalent number of allowances, in an amount equal to a 

specific amount of emissions, that the affected EGU receives per 

one net MWh of generation eligible for the set-aside. The EPA

proposes to set the allocation rate equal to the emission rate 

standard (on a net -basis) for new NGCC units under 111(b), in 

order to align the generation incentives across EGUs eligible 

for the set-aside and the type of new emitting source that would 

generate more absent this set-aside (&&&cite to 111(b) rule)..

Specifically, an additional MWh of eligible generation would 

earn the affected EGU allowances equal to the level of emissions 

permitted per MWh of net generation under the 111(b) new source 

standard, which is 1,030 lblbs/MWh-net. (Carbon Pollution 

Standards for new, modified, and reconstructed EGUs). The EPA 

requests comments on other values for the allocation rate (or, 

potentially, allocation rates).. For example the allocation rate 

may be the expected net emissions rate of newly constructed NGCC 

 

109 The EPA recognizes that under this lagged accounting procedure, if the

federal plan is replaced by a state plan in a future compliance period, the 

incentive to create eligible generation in the last compliance period subject 

to the federal plan is potentially diminished.
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units, the historic average emissions rate from NGCC units, or 

the NGCC or fossil steam uniformsource category-specific 

emissions performance rates underpromulgated in the Clean Power 

Plan EGs (see section VI inof the final EGs).

The EPA proposes to calculate an NGCC unit’s capacity 

factor based on the previous compliance period’s net generation 

and the net summer capacity of the unit. The EPA is proposing to 

require affected EGUs to report net generation to the agency

(see section V.H for proposed monitoring and reporting 

requirements)..110 The EPA proposes to use net summer capacity as 

reported to EIA. In the alternative, the EPA proposes to require 

that NGCC units report net summer capacity directly to the EPA; 

we would add EGU-level net summer capacity by adding it as a 

required data field in the certificate of registration that a 

unit’s owner or operator would submit to the agency per the 

procedure detailed in(see section V.G. The EPA requests comment 

on the relative efficiencyH of obtaining net summer capacity 

from data reported to EIA or of adding net summer capacity as a 

required data field on the certificate of registration.this 

 

110 See section V.H of this preamble for proposed monitoring and 

reporting requirements. The EPA proposes to make the reported 

generation data available to the public on the agency’s Web site.
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preamble). The EPA notes that the EIA net summer capacity data 

is reported at the generator level not the affected-EGU level;

if we add this data point to the certificate of registration it 

would be reported at the affected-EGU level, which would 

facilitate calculation of the capacity factors. The EPA also 

requests comment on whether the “maximum load value,” which is a 

parameter that EGUs report to the EPA in their monitoring plans, 

is a reasonable proxy for EGU-level net summer capacity for 

these calculations. The EPA also requests comment on an 

alternative approach of basing the capacity-factor calculation 

on nameplate capacity instead of net summer capacity, or other 

approaches to the calculation.

The EPA proposes to determine the size of the output-based 

set-aside once, before the start of the program, and not to 

change the size thereafter. The EPA proposes to determine the

size of the set-aside assuming that it would incentivize 

existing NGCC to increase utilization to a 60 percent capacity 

factor. The assumed 60 percent capacity factor offers a way to

limit the size of this set-aside, which allows the remainder of 

the allowances in a given compliance period to be allocated 

through the historic-generation approach (as detailed above) and 
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the other proposed set-asides (as detailed below). Furthermore, 

limiting the size of the set-aside avoids the risk of 

incentivizing too much generation from eligible sources, as 

discussed further in the Allowance Allocation Proposed Rule TSD.

The EPA proposes to determine the size of the output-based 

set-aside using 2012 baseline data from the Clean Power Plan 

EGs.111 The EPA would calculate the size of the set-aside as 10 

percent of the NGCC capacity in the state112 multiplied by the 

hours in a year multiplied by the allocation rate for the setaside. The EPA takes comment on the proposed capacity data used 

as the basis for determining the size of the output-based setaside, and alternative sources of capacity data that may be used 

for determining its size. 

The set-asides resulting from this proposed approach are 

shown in Table 9 of this preamble. The set-asides in the table 

would apply to every compliance period except for the first 

compliance period for which there would be no output-based setaside. Although the size of the set-aside would remain the same 

for each compliance period, as the mass goals decrease with each 

 

111 CO2 Emission Performance Rate and Goal Computation TSD for the 

CPP Final Rule.

112 The sum of net summer capacity for affected NGCC units in the 

2012 baseline for the Clean Power Plan EGs (CO2 Emission 

Performance Rate and Goal Computation TSD for the CPP Final Rule).
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step in the Interim Period and to the Final Period, the setasides would constitute an increasing share of a state’s mass 

goal. The Allowance Allocation Proposed Rule TSD further details

the proposed approach to determine the size of the set-aside. 

The EPA requests comment on a potential limit for the size of 

the set-aside in a compliance period based on a percentage of 

the state’s total allowances for the compliance period.

Table 9. Proposed Size of Output-Based Set-Aside for the Second 

Compliance Period and Later

(Short Tons)

State Allowances in outputbased set-aside

Alabama 4,185,496

Arizona 4,197,813

Arkansas 2,102,538

California 8,458,604

Colorado 1,348,187

Connecticut 1,090,811

Delaware 649,190

Florida 12,102,688

Georgia 3,563,104

Idaho 246,638

Illinois 1,598,615

Indiana 1,106,150

Iowa 492,510

Kansas 62,257

Kentucky 288,730

Lands of the Fort Mojave Tribe 248,127

Lands of the Navajo Nation 0

Lands of the Uintah and Ouray Reservation 0

Louisiana 2,207,879
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Maine 563,925

Maryland 103,762

Massachusetts 2,439,991

Michigan 2,105,786

Minnesota 909,724

Mississippi 3,132,671

Missouri 815,210

Montana 0

Nebraska 144,635

Nevada 2,326,529

New Hampshire 542,721

New Jersey 3,413,100

New Mexico 627,085

New York 3,815,381

North Carolina 2,120,178

North Dakota 0

Ohio 1,757,326

Oklahoma 3,121,167

Oregon 1,291,027

Pennsylvania 4,392,931

Rhode Island 778,307

South Carolina 1,029,366

South Dakota 130,831

Tennessee 632,949

Texas 15,990,657

Utah 825,586

Virginia 3,011,811

Washington 1,383,060

West Virginia 0

Wisconsin 1,181,175

Wyoming 45,114

After identifying NGCC units with average capacity factor 

above 50 percent, the EPA would then calculate the amount of 

allowances these affected EGUs would receive from the outputbased set-aside as the unit’s net generation above an average 

capacity factor of 50 percent in the preceding compliance 
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period, multiplied by the 111(b) rate standard for NGCC units of 

1,030 lb/MWh-net. (The proposed approach to determine the size 

of the set-aside is detailed below.)

Given the proposed limit on the total size of the setaside, and the amount of potential generation eligible for the 

set aside, there may be fewer allowances available in the set 

aside than can be earned at the allocation rate. The EPA 

proposes that, if the amount of total generation eligible for 

the set aside multiplied by the allocation rate exceeds the size 

of this set-aside, then the allowances in this set-aside would 

be allocated to eligible generation on a pro-rata basis. 

The EPA proposes that if the number of allowances allocated 

from the set aside is less than the size of this set-aside, then 

the remaining allowances would be distributed to all affected 

EGUs using the historic-generation based-approach described 

above.

The EPA proposes to provide notice of the capacity and 

generation data used to calculate allocations from the setaside, and the resulting allocations, by August 1 of the first 

year in each compliance period, e.g., by August 1, 2025 for the 

compliance period that commences in 2025 (and based on the data 
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from the prior compliance period). The agency proposes to 

provide 30 days for comment on the data and allocations, until 

August 31, and to provide notice of the final set-aside 

allocations by November 1 of the same year and record the 

allocations in the source accounts at that time. The EPA 

requests comment on other approaches to providing notice of the 

data and allocations.

The EPA requests comment on all aspects of the proposed 

approach to calculate output-based set-aside allocations. 

Further details are in the Allowance Allocation Proposed Rule 

TSD in the docket.

The EPA proposes to determine the size of the set-aside 

based on the total allowances in each state, the allocation 

rate, the capacity factor above which eligible generation may 

receive the output-based allocations, and an average capacity 

factor across all sources potentially eligible for allowances 

from the set-aside. In particular, the EPA proposes that the 

share of the total used for the set-aside be equal to the 

allocation rate (i.e., 1,030 lb/MWh-net), multiplied by the 

amount of potential generation from all NGCC-unit affected EGUs

in the state above an average capacity factor of 50 percent and 

below an average capacity factor of 60 percent, based on 2012 

data as detailed below. The 50 percent average capacity factor 
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is the capacity factor above which eligible generation may 

receive the output-based allocations. The 60 percent capacity 

factor limits the size of this set-aside, which increases the 

share of the allowances allocated based on historic-generation

(as detailed above). Maintaining a relatively large share of 

allowances allocated based on historic generation provides all 

EGUs subject to the mass-based plan certainty in their allowance 

allocation. Furthermore, limiting the size of the set-aside 

avoids the risk of incentivizing too much generation from 

eligible sources.

The EPA proposes to determine the size of the output-based 

set-aside for each state using 2012 baseline data from the Clean 

Power Plan EGs (&&&cite to EGs baseline TSD). The EPA would 

calculate the size of the set-aside as 10 percent of the NGCC 

capacity in the state113 multiplied by the hours in a year (8,760 

hours) multiplied by the allocation rate for the set-aside 

(1,030 lb/MWh-net)..

The set-asides resulting from this proposed approach are 

shown in Table &&&. The set-asides in the table would apply to 

every compliance period except for the first compliance period 

 

113 The sum of net summer capacity for affected NGCC units in the 

2012 baseline for the Clean Power Plan EGs (&&&cite to EGs baseline 

TSD).
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for which there would be no output-based set-aside. Although the 

size of the set-aside would remain the same for each compliance 

period, as the mass goals decrease with each step in the Interim

Period and to the Final Period, the set-asides would constitute 

an increasing share of a state’s mass goal. The Allowance 

Allocation Proposed Rule TSD further details the proposed 

approach to determine the size of the set-aside. The EPA 

requests comment on a potential limit for the size of the setaside in a compliance period based on a percentage of the 

state’s total allowances for the compliance period.

Table &&&. Proposed Size of Output-based Set-aside for the 

Second Compliance Period and Later

(Short Tons)

The EPA proposes to determine the size of the output-based 

set-aside once, before the start of the program, and not to

change the size. The EPA also requests comment on updating the 

size of the set-aside once after the start of the Final Period 

using data from 2030 or another year, and also seeks comment on 

updating the size of the set-aside more than once after 2030, 

for example every six or eight years. If the EPA updated the 

size of the set-aside, we would provide notice of the data upon 

which we intended to rely and opportunity for comment; the EPA 
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requests comment on this approach. 

Given the proposed limit on the total size of the setaside, and the amount of potential generation eligible for the 

set aside, there may be fewer allowances available in the set 

aside than can be earned at the allocation rate. The EPA 

proposes that, if the amount of total generation eligible for 

the set aside multiplied by the allocation rate exceeds the size 

of this set-aside, then the allowances in this set-aside would 

be allocated to eligible generation on a pro-rata basis. 

The EPA proposes that if the number of allowances allocated 

from the set aside is less than the size of this set-aside, then 

the remaining allowances would be distributed to all affected 

EGUs using the historic-generation based-approach described 

above.

The EPA also requests comment on extending output-based 

allocation from this set aside to affected steam generating 

units. Output-based allocation for steam generating units may 

increase generation subject to the mass limit, leading to 

reduced generation and emissions from new emitting sources. 

However, the EPA does not propose this approach because it is 

not as effective as output-based allocation to NGCC units. This 

is because output-based allocation to steam generating units

would incentivize generation from relatively high-emitting EGUs, 
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which would likely increase allowance prices as other emission 

reductions are made to respect the overarching mass limit. This 

approach would thus counteract the intended effect of lowering 

the production cost from sources subject to the proposed massbased federal plan (compared to emitting sources not subject to 

the plan). The EPA also requests comment on extending outputbased allocation from this set-aside to zero-emitting 

generators.

The EPA solicits comment on the general merits of the 

proposed set-aside and the output-based allocation used under

this set-aside. In addition, the agency solicits comment on how 

such an approach could be targeted to improve implementation of 

the proposed mass-based trading federal plans and improve 

overall environmental and economic performance. In particular, 

the EPA solicits comment on which affected EGUs or other 

generation sources should receive any output-based allocation, 

the proper allocation rate(s), the total size of the set-aside, 

and from which compliance period’s total allowances the setaside should be drawn. 

b. Set-asides for Renewable Energy Projects 

The EPA proposes to provide a set-aside of allowances for 

distribution to renewable energy (RE) in each state covered by 

the proposed mass-based federal plan, and is also proposed for 
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the mass-based model rule. The agency is also taking comment on 

whether distribution should extend to demand-side energy 

efficiency (DS-EE) and combined heat and power (CHP) projects. 

Under this program, the EPA would reserve a percentage of each 

state’s allowances (i.e., a percentage of its mass) in a setaside account for each state. Developers of RE projects could

apply to receive set-aside allowances based on the projected 

generation from eligible RE capacity.

Such a program will serve to facilitate source compliance 

with the EGs. First, the set-aside willThis set-aside is 

expected to address concerns regarding leakage by lowering the 

marginal cost of production of the incented clean energy 

technologies within the state. This will make RE more 

competitive against new sources, reducing the potential for 

leakage to new sources. 

All else being equal, this also lowers the cost of 

generation in the state overall, and thus can avoid leakage of 

generation to another state. By lowering the cost of generation,

it may also lower its price for electrical consumers, depending 

on how much the increased cost of allowance for affected EGUs is 

reflected in electricity costs. While the proposed set-asides 

would provide additional incentive for the creation of 

additional RE capacity, it should also be noted that the 
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proposed mass-based trading program itself would provide 

incentive for new and existing low and zero-emitting generation.

The EPA is aware of at least one existing program that 

supports deployment of RE and demand-side EE using the proceeds 

from the auction of tradable CO2 allowances – the Regional 

Greenhouse Gas Initiative (RGGI). RGGI adopted an allocation 

approach in which states could invest auction proceeds to 

support DS-EE and RE deployment programs. It was recognized that 

such investment is a means to reduce the potential for emission 

leakage from a carbon cap-and-trade system in the United States

(in RGGI’s case, to sources located outside the RGGI states). As 

will likely be similar to the proposed federal plan here, RGGI 

only covers a subset of states. A RGGI staff proposal in 2008

recognized that reduced electricity demand can reduce the 

potential for emissions leakage of generation from a 

participating to a non-participating state, by reducing the 

demand for fossil fuel-fired electric generation, which in turn 

reduces the demand for CO2 allowances, and thus reduces allowance 

prices within the RGGI market.114 Under the RGGI program, more 

 

114 RGGI, Potential Emissions Leakage and the Regional Greenhouse 

Gas Initiative (RGGI), Final Report (March 2008), available at 

www.rggi.org/docs/20080331leakage.pdf.
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than 90 percent of CO2 allowances are distributed through 

auction, and more than 60 percent of cumulative investment of 

auction proceeds has been directed to DS-EE.115 While not a setaside program per se, the basic concept is similar in that RGGI 

uses the proceeds from the auction of emission allowances to 

fund programs for DS-EE and RE that are both complementary with 

the overall purpose of the program (to reduce CO2 emissions), and 

which also assist in ameliorating the leakage concern.

The EPA is proposing that a unique set-aside would be 

created for each state covered by a mass-based federal plan.In 

the context of the proposed federal plan, the EPA is proposing 

that it would create a unique set-aside for each state covered 

by a mass-based federal plan. Under a model rule, the state 

would create this set-aside. The allowances in each set-aside 

would be reserved from each vintage of the assigned mass goal to 

that state prior to allocation of allowances to sources. The EPA 

is proposing that five percent of allowances will be reserved 

 

115 RGGI, “Second Control Period CO2 Allowance Allocation,” March 

25, 2015. Available at 

www.rggi.org/docs/CO2AuctionsTrackingOffsets/Allocation/SCP_Allo

wance-Allocation.pdf. RGGI, Investment of RGGI Proceeds through 

2013, April 2015. Available at 

www.rggi.org/docs/ProceedsReport/Investment-RGGI-ProceedsThrough-2013.pdf.
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from the allocation for each state for the purpose of the setaside. We are also requesting comment on options for a 

percentage of allowances to be reserved ranging from 1 to 10 

percent of total allowances in each state. The proposed 

percentage has been determined to provide a meaningful 

additional incentive for RE activities in each state, while 

assuring that the vast majority of allowances are freely 

allocated to affected EGUs. The EPA made this conclusion based 

upon determining an appropriate volume of set-aside resources 

that, at a range of possible allowance prices, are projected to 

incent the development of additional RE projects. The analysis 

is provided in the docket as part of the AllocationsAllowance 

Allocation Proposed Rule TSD. We note that, under the proposed 

framework, these allowances would be available to affected EGUs 

either in the marketplace or through subsequent distribution of 

unclaimed set-aside allowances, and thus the provision of these 

set-asides does not affect the overall stringency of the 

program.

In Sec. &&&, In section V.D.5 of this preamble, below,

the EPA is proposing that the size of the RE set-asides may grow 

over time as certain units shift out of the program.

It is the agency’s intention that states electing to 

submit a state allowance-distribution methodology under the We 
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are proposing, as part of the mass-based federal plan will have 

the flexibility to determine their allowance-distribution 

method, and thus may determine whether to include a set-aside 

and how such a set-aside will be distributed if they choose to 

submit a state allowance-distribution methodology. The allowance 

distribution methodology must still contain an allocation 

strategy to address leakage, unless the jurisdiction can make 

the justification that leakage is already addressed by existing 

policy, by unique characteristics of the jurisdiction or by some 

other aspect of their state plan.

We are proposingmodel rule, that a project is eligible to 

receive set-aside allowances if it is renewable energy (RE) that 

meets the eligibility requirements for rate-based ERC issuance 

as specified in section IV.C of this proposal 

Sec.IV.Candpreamble and section VIII.K of the final guidelines 

Sec. VIII.KEGs. This includes, for example, the requirement that 

only capacity incremental to 2012 is eligible for the set-aside.

The agency is requesting comment on an additional potential

condition that would limit eligibility to project providers that 

are also the owners or operators of affected EGUs. This approach 

has precedent in the eligibility requirements for the Acid Rain 

ProgramARP set-aside, and assures thatwould limit the entities 

eligible to receive set-aside allowances areto those that are
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subject to the federal plan.

The EPA is proposing that eligible RE capacity must meet 

the following conditions regarding geographic eligibility. for 

both the federal plan and model rule. Eligible RE projects must 

be located in the mass-based state for which the set-aside has 

been designated. The agency invites comment on whether capacity 

outside the state should be recognized, and how that could be 

implemented. The EPA also proposes that the generation for which 

an entity receives allowances from the set-aside would not be 

eligible for ERC issuance in rate-based states. 

As specified in section IV.C of this preamble, the EPA is 

proposing that the same RE measures are eligible to receive setaside allowances under a mass-based federal plan as would be 

eligible for ERC issuance under a rate-based federal plan. and 

the model rule. Specifically, the following RE measures are 

eligible: on-shore wind, solar photovoltaics (PV), concentrated 

solar power, geothermal power, and hydropower. The RE measure 

must also have the capacity to provide data quantified by a 

revenue-quality meter, as described in the eligibility 

requirements for rate-based ERC Issuance in Sec.IV.F.2 above.a 

requirement that is further discussed in section IV.D.8 of this

preamble. New nuclear units and capacity uprates at existing 

nuclear units are not proposed to be eligible to receive set-
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aside allowances, as we do not think a set-aside used as an

incentive for incremental nuclear capacity is a useful way to 

address leakage to new sources during the performance period, 

due to unique costs and development timelines for incremental 

nuclear power. All other proposed aspects of the RE eligible 

measure types described in section IV.C of this preamble and the 

requests for comment included within that section also apply in 

the mass-based set-aside context. for both the proposed massbased federal plan and the proposed mass-based model rule. For 

example, we are requesting comment on the inclusion of other RE 

measures, incremental nuclear, demand-side EE measures, CHP and 

any other technologiesemission reduction measures beyond those 

mentioned here, as long as they meet the eligibility 

requirements outlined in the final EGs for rate-based crediting,

as eligible measures to receive set-aside allowances. We 

particularly request comment on how a set-aside to provide an 

incentive from these particular measures will serve to address 

leakage to new sources. We also request comment on the 

implications of the inclusion of such technologies for the 

streamlined implementation of projection-based EM&V requirements 

of the set-aside specified below in a federal plan context 

across the applicable jurisdictions, while still maintaining 

necessary rigor. We request comment on the appropriateness of 
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the biomass eligibility optionstreatment requirements offered 

for comment in Sec.section IV.F.2C.3 of this preamble in the 

context of a mass-based set-aside context to address leakage.. 

We request comment on requirements for the treatment of CHP and 

WHP, in the context of the mass-based set-aside. We also request 

comment on appropriate processes through which, after the 

federal plan is finalized, the EPA and/or stakeholders could 

make a demonstration of the appropriateness of new measure types 

and the EPA could evaluate and approve the demonstration so that 

a new measure type can be considered eligible for the set-aside.

To demonstrate that an RE project meets the requirements 

proposed above, in the context of a mass-based federal plan, it 

is proposed that the project proponent must provide the 

following: documentation of the nature of the project and that 

it meets eligibility requirements, documentation that it will be 

located within the state in question, and a projection of 

expected annual megawatt-hourMWh generation for an RE project. 

The EPA must approve the documentation of eligibility and the 

projection of megawatt-hoursMWh before the project becomes 

eligible for a distribution of the set-aside allowances. In 

addition, the proponent must register for a general account in 

the EPA tracking system where the allowances would be recorded. 

See section40 CFR 62.16320 for the requirements to establish a 
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general account. While the EPA is proposing to allow eligible 

resources to use a general account to receive any allowances 

allocated under this section, the EPA requests comment on 

extending the designated representative provisions in section40 

CFR 62.16290 to eligible resources instead of the general 

account provisions. Requiring eligible resources to submit 

information similar to that collected in the certificate of 

representation in section40 CFR 62.16305 and to appoint a 

designated representative to act on behalf of all 

owners/operators for all projects requesting allowances may 

improve the EM &V process by making the eligible resources more 

accountable. The EPA requests comment on what documentation 

would be required if other measure types were considered 

eligible to receive set-aside allowances. We propose that the 

same process for approval of projects be applied in a model 

rule, with the state taking the approving role instead of EPA.

The EM&V requirements for the mass-based set-aside differ 

from those for rate-based ERC issuance, particularly because it 

is based upon projections provided prior to generation rather 

metered data provided after the generation occurs (though we are 

proposing that the projections will be checked against ex-post 

metered data). The projection method enables the distribution of 

set-aside allowances prior to the year during which the 
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generation occurs. The EPA feels this still provides sufficient 

rigor because the set-aside does not directly affect program 

stringency. The reason that stringency is not affected is 

because of key differences between issuance of credits and 

distribution of set-aside allowances. Under rate-based 

implementation, each decision to issue an ERC based on a 

quantification of RE generation affects the ultimate amount of 

allowable CO2 emissions, because the number of ERCs is determined 

by the amount of MWhs approved as eligible for ERC issuance. and 

the ERC does not exist until the issuance decision is made. Thus 

the amount of ERCs that are issued can affect the stringency of 

the rule. As a result, the EPA has laid out specific 

requirements (including EM&V procedures) in the final CPP, and 

in this proposed federal plan and model rule, to assure the 

environmental reliability of measures qualifying for ERC 

recognition under rate-based implementation. In contrast, any 

decision to recognize RE with set-aside allowance allocations 

under a mass-based approach does not affect the validity of the 

allowance itself and does not affect the CO2 emissions outcome 

because the ultimate amount of allowable CO2 emissions is 

determined by the total number of allowances initially created 

(regardless of how they are distributed). As a result, while the 

EPA believes it is reasonable to consider a minimum set of 
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qualifications for recognizing RE through these allowance setasides to assure that the RE generation that is incented is 

actually produced, the EPA does not believe the overall 

integrity of mass-based implementation is significantly affected 

by the robustness of whatever eligibility requirements the EPA 

ultimately sets for RE recognition through allocation from these 

set-asides. This being said, the agency is proposing to require 

robust demonstrations of the eligibility and EM&V projections 

for RE generation submitted for the set-aside, demonstrations 

that are based in the best practices of existing programs. This 

is necessary to assure the delivery of RE as a result of the 

set-aside.

The EPA proposes that the projections of megawatt-hoursMWh

provided will be the basis of the distribution of set-aside 

allowances. A satisfactory demonstration of the future RE 

generation from an eligible project must use technically sound 

quantification methods that are reliable, replicable, and

accompanied by underlying analytical assumptions and verifiable 

data sources used to demonstrate future performance. These 

methods, assumptions and data sources must be specified in 

documentation accompanying the projections. These projections 

and supporting documentation should all be provided in the setaside project application, and that application must be approved 
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by a third-party verifier. The EPA invites comment on these 

proposed requirements for projections. We also take comment on 

whether set-asides should be based ondistributed proportional to

actual megawatt-hoursMWh provided by the installation in a prior 

year or compliance period, or another form of historical 

generation data. This type of allocation method could also be 

similar to the structure proposed for the OBA set-aside. We 

propose that the same projection-based distribution basis be 

applied in a model rule, with the state taking the approving 

role instead of EPA.

The EPA is proposing the following process for distribution 

of RE set-aside allowances. Starting prior to the compliance 

period, and going forward through the compliance period, RE 

providers in each state will have an opportunity to apply to the 

EPA or a designated agent to be approved as eligible to receive 

set-aside allowances in their state. This application must 

include all the requirements outlined above, including 

projections of expected megawatt-hoursMWh of generation. The EPA 

is proposing to accept RE set-aside project applications up to a 

deadline of June 1 in the year prior to the year during which 

the RE generation occurs (the “generation year”). The EPA or its 

agent will review and approve the project as eligible and it 

will be entered into the pool of projects that will receive set-
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asides in any compliance period. If approved, the number of 

projected megawatt-hoursMWh in each generation year will be the 

basis of the number of allowances the provider will receive, as 

an input to the methodology specified below. The providers will 

have an opportunity to update projections for future generation 

years, these projections must be received by June 1 of the year 

prior to the generation year in question. 

On December 1 of the year prior to each year of the 

compliance period in question, the EPA is proposing to 

distribute allowances from the set-aside to approved providers. 

The agency is proposing to distribute set-aside allowances to 

approved RE providers pro-rata, with the number of allowances 

distributed to each provider according to the percentage of 

total approved RE megawatt-hoursMWh for that state that the 

approved MWHs from their project represent. This method is 

proposed because it treats all eligible RE projects equally in 

the distribution of set-aside allowance. It also inherently 

provides a more significant incentive in states with less 

eligible RE generation, but will become less significant as RE 

generation increases. We would also like to take comment on 

whether to restrict projects to a maximum number of allowances 

they can receive per megawatt-hourMWh of generation, such as 1 

allowance per megawatt-hourMWh.
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After each generation year, RE providers receiving 

allowances will have to provide an M&V report with the megawatthoursMWh of RE generation actually produced, to assure that they 

have met the projected level of generation. These M&V reports 

need to document that the generation was by an approved project, 

and the report should be approved by a third party verifier. As 

discussed in the rate-based approach EM&V section above, these 

data should be readily available from existing metering. The EPA 

requests comment on the process for submitting M&V reports with 

actual generation. 

If the project or program does not reach the megawatthoursMWh projected in a particular generation year, the 

unfulfilled megawatt-hoursMWh will be subtracted from that RE 

provider’s megawatt-hoursMWh eligible for the set-aside in the 

next generation year, or multiple years if the deficit exceeds 

the MWhs projected for the upcoming year. If this deficit is 

greater than 10 percent in a particular year, the provider will 

need to provide an explanation of the deficit and will be 

required to reevaluate their projections for future years. If 

such deficits continue through all three years of the any

performance period in which they participate, the provider will 

be disqualified from receiving future set-asides for the 

following compliance period. We also take comment on whether a 
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provider with continuing deficits should also be disqualified 

from receiving ERCs for some or all of the remaining performance 

periods. The agency requests comment on all of the specified 

aspects of this distribution process.

The EPA is proposing that once allowances have been 

distributed to all approved providers, any remaining allowances 

in the set-aside, such as set-aside allowances designated for 

projects that no longer exist, will be redistributed to affected 

EGUs in the state in a pro rata fashion on the same distribution 

basis as their initial allocations were made. It is proposed 

that this will occur immediately after the distribution of setaside allowances to eligible RE providers on December 1 of the 

year prior to the generation year in question. The EPA requests 

comment on this approach.

We propose that the same distribution process as outlined 

above be applied in a model rule, with the state taking the 

approving role instead of EPA.

The EPA is also seeking comment, in the context of the 

proposed rate-based federal plan and model rule, on whether a 

portion of this set-aside should be targeted to RE projects that 

benefit low-income communities. This benefit could be in the 

form of MWh provided to the low-income community, financial 

proceeds from the project primarily benefiting the low-income
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community, or the project lowering utility costs of low-income 

rate-payers. The EPA seeks comment on how a low-income d

community should be defined as eligible under this set-aside. We 

seek comment on how much of the set-aside should be designated 

as targeted at low-income communities. We also request comment 

on whether the methods of approval and distribution of 

allowances to projects that benefit low-income communities 

should differ from the methods that are proposed to apply to 

other RE projects.

The EPA seeks comment, in the context of the proposed ratebased federal plan and model rule, on all aspects of this 

proposed RE allowance set-aside program, including whether it 

should be included as part of a mass-based federal plan, the 

structure of the set-aside reserve, eligibility requirements for 

receiving set-aside allowances, demonstration of eligibility, 

and the process for distribution of allowances.

4. Provisions to Encourage Early Action

For purposes of the proposed mass-based federal plan, the EPA 

proposes to implement the Clean Energy Incentive Program (CEIP) by 

issuing early action allowances for actions located in or 

benefitting a state that are implemented after September 6, 2018 

and that generate zero-emitting MWh or reduce energy demand in in 

2020 and/or 2021. These early action allowances would be drawn 
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from a third set-aside of allowances from the general distribution 

methodology. The EPA believes it is reasonable to establish the 

total amount of the early action-set aside in an amount equal to 

the pool of matching allowances. Thus, the EPA proposes that the 

total early action set-aside would be of an amount equal to the 

pool of matching allowances: no more than 300 million CO2

allowances, depending on how many states are subject to a federal 

plan. 

The EPA proposes to distribute the 300 million early action 

set-aside allowances among the states based upon the amount of the 

reductions from 2012 levels each state must achieve relative to 

that of the other participating states. The EPA proposes to 

calculate these values as each state’s proportional share of the 

total difference between the 2012 baseline and the 2030 mass 

goals.116 See Table 10 of this preamble for the proposed set-asides 

for each state under the mass-based federal plan. The agency 

proposes to set aside 100 million early action allowances from 

each of the three years in the first compliance period (2022, 2023, 

 

116 The 2012 baseline is from the CO2 Emission Performance Rate and 

Goal Computation TSD for the CPP Final Rule. Where a state’s 

relative share of the reductions from 2012 levels would yield a 

set-aside of less than zero, the EPA proposes to assign such a 

state a set-aside equal to one percent of the state’s 2030 mass 

goal and adjust the remaining state set-asides accordingly. 
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and 2024) for a total of 300 million allowances to be set aside. 

While the table shows set-asides for every state, the EPA proposes 

to implement this set-aside, according to the amounts listed in 

Table 10, only for those states for whom the EPA is implementing 

the mass-based federal plan. The EPA also requests comment on other 

approaches for determining the size of this set-aside in the massbased federal plan.

For the purposes of the mass-based federal plan, the EPA is 

proposing to award early action allowances to two types of eligible 

projects installed after September 6, 2018 that are located in or 

benefit the state for which the EPA is implementing a federal plan:

• RE investments that generate metered MWh from any type of 

wind or solar resources; and

• Demand-side EE programs and measures implemented in lowincome communities that result in quantified and verified 

electricity savings (MWh).

The EPA proposes the following framework to implement the 

CEIP in the mass-based federal plan. First, the EPA proposes to 

create a set-aside of early action allowances for all federal-plan 

states, as described above. Second, the agency proposes to create 

an account of “matching” allowances for each state participating 

in the CEIP – regardless of whether a state is implementing a state 

plan or the agency is implementing a federal plan on its behalf. 
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This distribution would reflect each state’s pro rata share of a 

federal pool of additional ERCs – based on the amount of the 

reductions from 2012 levels the affected EGUs in the state are 

required to achieve relative to those in the other participating 

states117 – which would be limited to the equivalent of 300 million 

short tons of CO2 emissions. Thus, states whose EGUs have greater 

reduction obligations will be eligible to secure a larger 

proportion of the federal allocation upon demonstration of 

quantified and verified MWh of RE generation or demand side-EE 

savings from eligible projects realized in 2020 and/or 2021. The 

EPA intends that a portion of these matching allowances would be 

reserved for eligible wind and solar projects, and a portion would 

be reserved for eligible EE projects implemented in low-income 

communities. The agency recognizes that there have been historic 

economic, logistical and information barriers to implementing EE 

programs in these communities, and therefore believes it is 

appropriate to reserve a portion of the federal pool to incentivize 

investment in these programs. The EPA is requesting comment on the 

size of reserve of matching allowances for eligible low-income EE 

programs as well as for eligible wind and solar projects. The EPA 

 

117 This is the same distribution method proposed above for the 

allocation of early action set-aside allowances to mass-based 

federal plan states.
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is proposing that unused allowances in either reserve would 

redistributed among participating states. This redistribution 

could be executed according to the pro-rata method discussed above. 

Alternatively, unused matching EE or RE allowances could be swept 

back into a federal pool and distributed to project providers on 

a first-come, first served basis. EPA requests comment on these 

ideas as well as alternative proposals regarding the method for 

redistributing matching ERCs, as well as the appropriate timing 

for such a redistribution.

Following the effective date of a federal plan for a state, 

the agency will create an account of matching allowances for the 

state that reflects the pro rata share of the 300 million short 

ton CO2 emissions-equivalent matching pool that the state is 

eligible to receive. Any matching allowances that remain 

undistributed after September 6, 2018118 will be distributed to 

those states with approved state plans that include requirements 

for CEIP participation, as well as to those states on whose behalf 

EPA is implementing a federal plan. These allowances will be

distributed according to the pro rata method outlined above. Unused 

matching allowances that remain in the accounts of states 

participating in the CEIP on January 1, 2023, will be retired by 

 

118 This may occur because not all states may elect to include 

requirements for CEIP participation in their state plans. 
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the EPA. The EPA seeks comment on whether the number of matching

allowances available to a state under the mass-based federal plan 

should be limited to a number equal to the number of early action 

allowances included in each federal plan state’s early action setaside.

Third, for any state subject to a federal plan, the EPA 

proposes to award early action allowances and matching allowances 

to eligible projects as follows, based upon the quantified and 

verified MWh of generation or savings achieved by the projects in 

2020 and/or 2021:

• For RE projects that generate metered MWh from any type of 

wind or solar resources: for every two MWh generated, the 

project will receive a number of allowances equivalent to 

one MWh from the state early action allowance set-aside, 

and a number of matching allowances equivalent to one MWh 

from the EPA.

• For EE projects implemented in low-income communities: for 

every two MWh in end-use demand savings achieved, the 

project will receive a number of allowances equivalent to 

two MWh from the state early action allowance set-aside, 

and a number of matching allowances equivalent to two MWh 

from the EPA. 

The EPA will address implementation details of the CEIP in a 
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subsequent action. Allowances awarded by the EPA pursuant to the 

CEIP may be used for compliance by an affected EGU with its 

emission standards in any compliance period and are fully 

transferrable prior to such use. The EPA proposes to distribute 

any remaining early action set-aside allowances in a state – after 

distribution to all eligible projects in the state – to the 

affected EGUs in the state on a pro-rata basis in proportion to 

the initial allocations made to those EGUs under the mass-based 

federal plan. 

As discussed in section V.E of this preamble, the EPA proposes 

to allow any state where a federal plan is being implemented to 

take responsibility for distributing allowances to affected 

sources. This will allow a state to tailor its allowancedistribution approach to the characteristics and preferences of 

the state. The EPA proposes that a state that chooses to replace 

the federal-plan allocations with a state-determined approach must 

include a CEIP set-aside, as authorized in section VIII.B.2 of the 

final EGs. The EPA intends that such a state would have the same 

flexibilities as a state implementing a full state plan with 

respect to implementation of the CEIP. That is, the state would 

not be required to implement a set-aside of the same size as 

proposed in Table 10 of this preamble, but rather could choose how 

many of its allowances to set-aside for the CEIP. 
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The EPA requests comment on all aspects of implementing the 

CEIP under a mass-based federal plan approach, including (1) The 

size of the early action allowance set aside; (2) the approach for 

distributing the early action allowance set-aside among states; 

(3) the timing of distribution of set-aside and matching 

allowances; (4) the amount of allowances awarded per eligible MWh 

generated or avoided; (5) the criteria for eligible projects, 

including criteria for awards to EE projects implemented in lowincome communities; (6) the mechanism for reviewing project 

submittals and issuing early action allowances; (7) EM&V 

requirements for eligible projects; and, (8) the number of early 

action and matching allowances that should be awarded for each ton 

of emissions reduced from eligible generation or low-income 

efficiency projects to ensure a robust response to the program. 

The EPA also seeks comment on how states, tribes and territories 

for whom goals have not yet been established in the final EGs may 

be able to participate in the CEIP in the future.

The EPA also requests comment on the proposed approach of 

requiring states to implement this program as a condition of a 

state choosing to determine its own allocation approach via a 

partial state plan or a delegation of the federal plan.
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Table 10. Proposed Clean Energy Incentive Program Early Action 

Allowance Set-Aside in the Mass-Based Federal Plan (Short Tons)

State

Set-Aside 2022 

through 2024

Alabama 3,122,306

Arizona 1,719,618

Arkansas 2,187,230

California 218,846

Colorado 2,223,192

Connecticut 69,415

Delaware 138,392

Florida 3,230,248

Georgia 2,755,623

Idaho 14,929

Illinois 5,968,721

Indiana 5,754,076

Iowa 2,191,183

Kansas 2,115,630

Kentucky 4,952,862

Lands of the Fort Mojave Tribe 5,885

Lands of the Navajo Nation 1,623,066

Lands of the Uintah and Ouray Reservation 175,509

Louisiana 1,497,428

Maine 20,739

Maryland 972,775

Massachusetts 170,471

Michigan 3,727,861

Minnesota 2,002,903

Mississippi 357,307

Missouri 3,771,322

Montana 1,310,344

Nebraska 1,481,695
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Nevada 336,288

New Hampshire 107,798

New Jersey 446,005

New Mexico 823,049

New York 557,771

North Carolina 2,674,590

North Dakota 2,150,635

Ohio 4,788,372

Oklahoma 2,067,006

Oregon 154,353

Pennsylvania 5,039,346

Rhode Island 35,674

South Carolina 1,652,802

South Dakota 264,207

Tennessee 2,178,084

Texas 10,400,192

Utah 1,401,189

Virginia 1,386,546

Washington 751,434

West Virginia 3,506,890

Wisconsin 2,393,870

Wyoming 3,104,324

5. Allocations to Units that Change Status

Units that retire. The EPA proposes that, if an affected 

EGU does not operate for two consecutive calendar years, the 

unit would continue to receive allocations for a limited number 

of years after it ceases operation, after which the allowances 

that would otherwise have been allocated to that unit would be 

allocated to the renewable energyRE set-aside for the state in 
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which the retired unit is located.119 Continuing allocations to 

non-operating units for a period of time reduces the incentive 

to keep a unit operating simply to avoid losing the allowance 

allocations for that unit (e.g., a unit that would otherwise be 

retired due to age and inefficiency). On the other hand, nonoperating units are no longer emitting and so do not need 

allowances. The EPA believes that the proposed approach of 

allocating allowances for a specified, but limited, period after 

a unit ceases operating is a reasonable middle ground approach.

The proposed approach also allows the renewable energyRE setasides to grow over time.

The EPA proposes to record allowances for each year of a 

multi-year compliance period at once, seven7 months prior to the 

start of each compliance period, as discussed above. The agency 

proposes that, if an affected EGU does not operate for two full 

calendar years, then starting with the next compliance period 

for which allowances have not yet been recorded, the allowances 

that would otherwise have been allocated to the unit would be 

allocated to the renewable energyRE set-aside. As a result, the 

 

119 This is similar to the approach taken in CSAPR of continuing 

allocations to retired units for four years and then allocating 

the allowances to a set-aside; in CSAPR the set-aside is for new 

units.
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number of years of non-operation for which a retired unit would 

receive allocations would vary depending on when a unit retires. 

For example, if an affected EGU does not operate for the first 

two calendar years of a three3-year compliance period, then 

starting with the next compliance period the allowances that 

would otherwise have been allocated to that unit would be 

allocated to the renewable energyRE set-aside — in other words 

the unit would receive allocations for three3 years of nonoperation. As a further example, if an affected EGU does not 

operate for both calendar years of a two2-year compliance 

period, then starting with the compliance period after the next 

compliance period the allowances would be allocated to the 

renewable energyRE set-aside — in other words the unit would 

receive allocations for four4 years of non-operation.

The agency requests comment on this approach for treatment 

of allocations to affected EGUs that retire, including on the 

number of years of non-operation for which a unit would continue 

to receive allocations. The EPA also requests comment on an 

alternative of distributing such allowances to the set-aside for 

output-based allocations, or to the remaining affected EGUs in 

the state in a pro-rata fashion (on the same distribution basis 

as the initial allocations were made), instead of allocating 

such allowances to the state’s renewable energyRE set-aside. The 
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agency requests comment on a further alternative approach, which 

would be to continue allocations to the retired units. The EPA 

also requests comment on treatment of allocations to units that 

are in long-term cold storage.

The EPA also requests comment on approaches that might 

consider extending the period for which a retired unit continues 

to receive allocations to address (&&&).

Units that are modified or reconstructed. Similar to the 

approach for an affected EGU that retires, the EPA proposes 

that, if a unit is modified or reconstructed such that it is no 

longer an affected EGU, then starting with the next compliance 

period for which allowances have not yet been recorded, the 

allowances that would otherwise have been allocated to the unit 

would be allocated to the renewable energyRE set-aside. The EPA 

requests comment on this proposed approach, including on the 

number of years for which a unit would continue to receive 

allocations. The agency also requests comment on an alternative 

of distributing such allowances to the set-aside for outputbased allocations, or to the remaining affected EGUs in the 

state in a pro-rata fashion (on the same distribution basis as 

the initial allocations were made), instead of allocating such 

allowances to the state’s renewable energyRE set-aside. The 

agency requests comment on a further alternative approach, which 
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would be to continue allocations to the modified or 

reconstructed units.

E. State-determined Allowance Distribution

The EPA proposes to allow any state to replace the EPAdetermined federal-plan allowance-distribution provisions in the 

mass-based trading program with state-developed allowancedistribution provisions. In this way, a state could choose how 

to distribute initial allowance allocations among its affected 

EGUs (and other entities). 

The EPA believes that this option may offer significant 

appeal, because it will allow a state to tailor its allocation 

approach to the characteristics and preferences of the state. A 

state would be able to design its allocation approach to address 

its particular state priorities, whether they are protecting 

low-income consumers, supporting local industries, or other 

goals. The EPA anticipates that a state would have great 

flexibility in its allowance distribution approach and could 

take advantage of allocation options discussed in this proposal 

as well as other allocation options a state might prefer. States 

could auction allowances and rebate the revenue to consumers, or 

allocate all allowances to load-serving entities, while 

mandating that the value be passed through to vulnerable 

consumers. The EPA believes that the state-determined allocation 
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approach offers significant advantages and solicits comment on 

how to ease its application by states. This is similar to the 

approach taken in the Cross-state Air Pollution Rule (CSAPR) and 

Clean Air Interstate Rule (CAIR) where the EPA adopted rules

allowing states to submit state implementation plans (SIPs) with 

provisions replacing the allowance-distribution provisions in 

the CSAPR or CAIR FIPs, respectively, while remaining in the 

trading programs under those FIPs (76 FR 48208; August 8, 2011, 

71 FR 25328; April 28, 2006). In both CSAPR and CAIR, some 

states have chosen to determine their own allocations under the 

FIPs. This form of SIP that can replace the allowancedistribution provisions in CSAPR or CAIR is termed an 

“abbreviated SIP revision.” In this proposed mass-based trading 

federal plan, the EPA proposes that a state may choose to submit 

a “state allowance-distribution methodology” (analogous to an 

abbreviated SIP revision) to replace the federal-plan allowancedistribution provisions with allowance-distribution provisions

of its choosing. 

The mechanism the agency envisions is in the nature of a 

partial state plan or (for any future changes in a state’s 

allocation methodology) a partial state plan revision. (We 

request comment below on the advantages and disadvantages of 

allowing a state to handle allocations via a delegation of 
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federal plan authority.) In general, under the proposed 

approach, the procedural requirements states and the agency must 

follow, including public notice requirements, for the submission 

and approval of state plans, would be required here.

The EPA intends to provide the states with substantial 

flexibility in choosing approaches to distribute their

allowances in a state allowance-distribution methodology. The 

EPA proposes that a state may choose any approach, including 

auctions or other methods the EPA is not proposing here, 

provided the state’s approach addresses leakage and also 

implements the Clean Energy Incentive Program. The EPA is also 

requesting comment on any other appropriate constraints to 

impose on state allowance-distribution methodologies.

The Clean Power Plan EGs require mass-based state plans to 

include a demonstration that they have addressed the risk of 

leakage, and the EGs provide several options for doing so (Clean 

Power Plan EGs, sectionsee sections VII.D and VIII.LJ of the 

final EGs). One of the options provided in the EGs is to address 

leakage through an allowance distribution approach that provides 

incentive to counteract leakage. In the mass-based trading 

federal plan, the EPA’s proposed approach to allocate allowances 

would address leakage using two allowance set-asides, one for 

output based allocation and one for renewable energyRE projects, 
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as detailed in section V.D.3 of this preamble. The EPA believes

that a state allowance-distribution methodology, which would 

replace the federal-plan allocation provisions, must also 

address leakage. The EPA proposes that a state allowancedistribution methodology must address leakage by providing 

incentive to counteract leakage, e.g., by including allowance 

set-asides like the output-based allocation and RE set-asides 

detailed in section V.D.3 of this preamble, or other allocation 

approaches designed to counteract leakage. The EPA requests 

comment on this proposed approach for addressing leakage in a 

state allowance-distribution methodology and on any other 

approaches for doing so. The EGs provide an additional option 

for state plans to address leakage, where a state would provide 

a demonstration that leakage will not occur (without 

implementing any of the strategies specified in the EGs) due to 

specified characteristics of the state (Clean Power Plan EGs, 

section VIII.LJ of the final EGs). In this federal plan 

proposal, the EPA requests comment on an alternative option 

where a state that chooses to submit a state allowancedistribution methodology could provide a demonstration that 

leakage will not occur (without implementing the allocation

strategies specified here) due to specific characteristics of 

the state; the EPA proposes that such demonstration must meet 
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the requirements in the final EGs, including support by credible 

analysis, for such a demonstration (see final EGs section 

VII.D). The EPA notes that a state’s allowance-distribution 

methodology may also include other set-aside approaches that are 

not designed to counteract leakage.

The Clean Power Plan EGs provide forestablished a Clean 

Energy Incentive Program (section VIII inof the final EGs). The 

EPA proposes that a state allowance-distribution methodology, 

which would replace the federal-plan allocation provisions, must 

also include a Clean Energy Incentive Program, as detailed in 

section V.D.4 of this preamble.

Under the proposed approach of providing for states to 

determine their allowance distribution approaches in the federal 

plan mass-based trading program, the affected EGUs in a state

that submitted a state allowance-distribution methodology, which 

the EPA approved, would participate in the federal plan massbased trading program, but with allowance distribution 

determined by the state instead of by the EPA.

The EPA proposes that a state must submit to the 

Administrator tables specifying the unit-level allowances in an 

electronic format specified by the Administrator and by the 

specified deadlines applicable to each compliance period (see 

Table &&&11 of this preamble for proposed submission deadlines).
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The EPA proposes that a state may submit a state allocation 

methodology for any compliance period, including the first 

compliance period, which would comprise the years 2022, 2023,

and 2024. The EPA proposes that a state submitting a state 

allowance-distribution methodology to modify the federal plan 

allowance-distribution provisions must do so for all years 

within a compliance period (e.g., for all three3 years in a 

three3-year compliance period).

The EPA proposes that, if the state’s allowancedistribution provisions meet certain requirements and the state 

allowance-distribution methodology does not change any other 

provisions in the proposed mass-based trading program, then the 

agency would likely approve the state allowance-distribution

methodology. In the state allowance distribution methodology, 

the state could distribute allowances to affected EGUs or other 

entities (such as renewable energyRE facilities) or could 

auction some or all of the allowances. The agency proposes that 

for EPA approval, the state allowance-distribution methodology

provisions would have to meet the following requirements. The 

provisions would have to address leakage as discussed above. The 

provisions would have to provide that, for each year for which 

the state allowance-distribution provisions would apply, the 

total amount of allowances distributed could not exceed the 
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applicable mass goal for that state for that year. A state’s 

methodology under this proposed approach could provide that the 

total amount of allowances distributed is less than the 

applicable mass goal.120 The EPA proposes that a state’s 

allowance-distribution provisions would replace the EPA’s 

allocation provisions completely – a state would not have the 

option of implementing only a portion of its allocations (e.g.,

only set-asides) and having the EPA implement the remainder of 

its allocations. Additionally, the EPA proposes that a state 

allowance-distribution methodology must provide for allowances 

to be issued in short tons.

The allocation (or auction) of allowances would be final 

and could not be subject to modification. Additionally, the 

state’s provisions could not change any other provisions of the 

proposed mass-based trading program with regard to the 

allowances (e.g., the deadlines for allocation recordation, or 

requirements for transfer or use of allowances) or any other 

aspect of such trading programs.

 

120 A state allowance-distribution methodology under this proposed 

approach, which is analogous to an abbreviated SIP revision, could 

provide that the total amount of allowances distributed is less 

than the applicable mass goal, pursuant to the reserved authority 

to states to set emission standards more stringent than federal 

standards under CAA section 116.
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In order for a state allowance-distribution methodology’s 

provisions to replace the EPA’s allowance-distribution 

provisions for a given compliance period, a state would have to 

submit the state allowance-distribution methodology by a 

deadline that would provide the agency sufficient time to review 

and approve it, and to submit the allowance table meeting the 

specified electronic format by a deadline that would provide 

sufficient time to record the unit-by-unit allowances in source 

accounts. The EPA believes that about twelve12 months — starting 

from the date of receipt of a state allowance-distribution

methodology — is sufficient to complete the agency’s review and 

approval process, which would have to provide an opportunity for 

public comment on the approval (or disapproval) action. Thus, 

the EPA proposes the following deadlines, in Table &&&,11 of 

this preamble, for submission to the agency of state allowancedistribution methodologies and unit-level allowances, and for 

the EPA’s recordation of allowances, for each compliance period.

The EPA would review and approve state allowance-distribution 

methodologies in the twelve12 months between the proposed 

deadline for states to submit their methodologies and the 

proposed deadline for states to submit unit-level allowance 

tables. The proposed deadline for submission of allowance tables 

is three3 months before the proposed deadline for the agency to 
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record allowances in source accounts. The EPA proposes to record 

allowances in source accounts by the recordation deadlines.

Table &&&.11. Proposed Deadlines for Submission of State

Allowance-Distribution Methodologies and Unit-Level Allowances

and for Recordation

First compliance 

period for which 

allowances would 

be distributed

Deadline for 

submittal of

state allowancedistribution

methodologies

Deadline for 

submittal of unitlevel allowance 

table

Deadline for the EPA to record 

allowances

2022, 2023, 2024 March 1, 2020 March 1, 2021 June 1, 2021

2025, 2026, 2027 March 1, 2023 March 1, 2024 June 1, 2024

2028, 2029 March 1, 2026 March 1, 2027 June 1, 2027

2030, 2031* March 1, 2028* March 1, 2029* June 1, 2029*

*This pattern of deadlines would hold for successive two2-year compliance 

periods.

The proposed deadlines for submission of state allowancedistribution methodologies are later than the state plan 

submission deadlines promulgated in the Clean Power Plan EGs. 

The agency anticipates that it can complete the approval process 

relatively quickly for a state allowance-distribution 

methodology due to its narrow scope.

The agency proposes to record the EPA-determined federal 

plan allocations only in the absence of an approved state plan 

or approved state allowance-distribution methodology. The EPA 

proposes to record in source accounts allowances that are 

determined by any state as soon as feasible after approval of a 

state allowance-distribution methodology and submission of the 

unit-level allowance table, and not to wait until the allowance 
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recordation deadline to do so.

In section V.D.2 of this preamble, the EPA proposes the 

allowance recordation deadline seven7 months prior to the start 

of the compliance period (i.e., June 1 of the prior year) and 

also requests comment on a recordation deadline thirteen13

months prior to the start of the compliance period (i.e.,

December 1 of the year two2 years before the compliance period

starts). If the EPA adopted the earlier recordation deadline on 

which it requests comment or any other deadline, then we would 

adjust the deadlines for submission of state allowancedistribution methodologies and submission of unit-level 

allowance tables accordingly.

The EPA proposes that a state may not replace EPAdetermined allocations for a compliance period for which federal 

plan allocations have already been recorded, for the same 

reasons that the agency proposes that a state may not replace a 

mass-based trading federal plan with a state plan for a future 

compliance period for which allowances have already been 

recorded, as discussed below in section V.F. of this preamble.

The agency requests comment on the proposed approach to 

allow states to determine allocations via state allowancedistribution methodologies and replace the federal-plan 

allowance-distribution provisions. The EPA requests comment on 
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the proposed schedule for submitting state allowance 

distribution methodologies to the agency, for submitting the 

resulting unit-level allowance tables to the agency, and for the 

agency to record allowances. The EPA requests comment on its 

proposed approach of not replacing EPA-determined allocations 

for a compliance period for which allowances have already been 

recorded. The agency also requests comment on an alternative 

approach where a state could notify the EPA of its intent to 

submit a state allowance-distribution methodology in advance, in 

which case the agency would hold off on recording EPA-determined 

allocations to allow more time for state-determined allowances

to be recorded, similar to the alternative timing approach 

discussed in section V.F of this preamble.

The EPA is also requesting comment on an alternative 

approach to provide the opportunity for a state to determine its 

allowance-distribution provisions in the federal plan mass-based 

trading program. The alternative approach on which the agency 

requests comment is to provide for a partial delegation of the 

federal plan – limited to the allowance-distribution provisions 

– to a state that wishes to determine its allowance-distribution

provisions. The EPA requests comment on the relative efficiency 

and ease of implementation of the two approaches (the state 

allowance-distribution methodology described above, or the 
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partial delegation). The agency requests comment on whether the 

partial delegation approach would provide sufficient flexibility 

for a state to choose any method to distribute its allowances 

including approaches that the EPA is not proposing here. See 

further discussion of delegations in section VI inof this 

preamble.

F. Treatment of States Entering or Exiting the Trading Program

If the EPA implements a mass-based trading program federal 

plan for any state, the agency will work with a state that 

wishes to replace the federal plan with an approved state plan 

to provide a smooth transition. The EPA proposes that a massbased trading federal plan could only be replaced by a state 

plan for a future compliance period for which allowances have 

not yet been recorded. For example, if a three3-year compliance 

period comprises 2022, 2023, and 2024, the EPA would record 

allowances in source accounts for 2022, 2023, and 2024 prior to 

2022. Once 2022, 2023, and 2024 allowances had been recorded, 

the first compliance period for which a state could replace the 

federal plan with its own plan would be for the period 

commencing in 2025. The EPA is proposing this stipulation for 

the timing of replacing a federal plan with a state plan due to 

the need to avoid disruption to sources already subject to the 

mass-based trading federal plan. Without this stipulation, a 
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state might withdraw from the mass-based trading program in the 

middle of a compliance period even though allowances that 

authorize emissions throughout that entire compliance period

would already be in circulation. In that circumstance, the EPA 

would then need to address whether and how to remove those 

allowances from circulation to prevent inflation of the 

allowable emissions at affected EGUs in the remaining states 

subject to the federal plans beyond the levels specified in the 

Clean Power Plan EGs. The EPA believes it is more reasonable to 

avoid this potential disruption by requiring that the 

replacement of a federal plan with a state plan be scheduled to 

coincide with the conclusion of the last compliance period for 

which allowances under the federal plan have already been 

recorded for that state. The EPA requests comment on other 

approaches to provide a smooth transition from federal-plan 

implementation to implementation by state plans, and on its 

proposed approach of not replacing a federal plan for any 

compliance period for which allowances were already recorded.

The agency requests comment on an alternative of providing 

for a state to give notice to the EPA of its intent to submit a 

state plan to replace the federal plan (or a state allowancedistribution methodology to replace federal-plan allocations), 

and for the agency to delay recording federal-plan allocations
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for sources in that state until a later date than proposed. The 

EPA requests comment on whether this alternative would help 

smooth the transition from federal-plan implementation to stateplan implementation, and on the trade-off between recording 

allowances in a timely way and providing this increased timing 

flexibility.

G. Allowance Tracking, Compliance Operations, and Penalties

The EPA proposes that the mass-based trading program use an 

allowance tracking and compliance system (ATCS) operated 

essentially the same way as the existing systems that are 

currently in use for Cross State Air Pollution Rule (CSAPR) and 

the Acid Rain Program (ARP) under Title IV. Under the proposed 

mass-based trading program, the CO2 program would be a separate 

trading program maintained in the EPA’s existing data system.

ATCS would be used to track the trading of CO2 allowances held by 

covered affected EGUs in facility level compliance accounts, as 

well as such allowances held by other entities or individuals. 

Specifically, ATCS would track the allocation of all CO2

allowances, holdings of CO2 allowances in compliance accounts 

(i.e., a facility level account for all affected EGUs at the 

facility) and general accounts (i.e., accounts for other 

entities such as companies and brokers), deduction of CO2

allowances for compliance purposes, and transfers of allowances 
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between accounts. The primary role of ATCS is to provide an 

efficient, automated means for affected EGUs to comply, and for 

the EPA to determine whether affected EGUs are complying, with 

the emissions limitations and any other requirements of the 

mass-based trading program. ATCS would also provide data to the 

allowance market and the public, including a record of ownership 

of allowances, dates of allowance allocations, allowance 

transfers, buyer and seller information, serial numbers of 

allowances transferred, emissions, and compliance information.

This information would be publicly available on the EPA’s Web 

site and in annual progress reports.

1. Designated Representatives and Alternate Designated 

Representatives

This section wouldThe EPA proposes to establish the

procedures for certifying and authorizing the designated 

representative, and alternate designated representative, of the 

owners and operators of an affected EGU and for changing the 

designated representative and alternate designated 

representative. These sections would also describe the 

designated representative’s and alternate designated 

representative’s responsibilities and the process through which 

he or she could delegate to an agent the authority to make 

electronic submissions to the Administrator. These provisions 
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would be patterned after the provisions concerning designated 

representatives and alternates in prior EPA-administered trading 

programs. 

The designated representative would be the individual 

authorized to represent the owners and operators of each 

affected EGU in matters pertaining to the mass-based trading 

program. One alternate designated representative could also be 

selected to act on behalf of, and legally bind, the designated 

representative and thus the owners and operators. Because the 

actions of the designated representative and alternate would 

legally bind the owners and operators, the designated 

representative and alternate would have to submit a certificate 

of representation certifying that each was selected by an 

agreement binding on all such owners and operators and was 

authorized to act on their behalf.

The designated representative and alternate would be 

authorized upon receipt by the Administrator of the certificate 

of representation. This document, in a format prescribed by the 

Administrator, would include: specified identifying information 

for the affected EGU and for the designated representative and 

alternate; the name of every owner and operator of the affected 

EGU; and certification language and signatures of the designated 

representative and alternate. All submissions (e.g., monitoring 
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plans, monitoring system certifications, and allowance 

transfers) for an affected EGU would have to be submitted, 

signed, and certified by the designated representative or 

alternate. Further, upon receipt of a complete certificate of 

representation, the Administrator would establish a compliance 

account in the ATCS for each facility with an affected EGU 

involved.

In order to change the designated representative or 

alternate, a new certificate of representation would have to be 

received by the Administrator. A new certificate of 

representation would also have to be submitted to reflect 

changes in the owners and operators of the affected EGU 

involved. However, new owners and operators would be bound by 

the existing certificate of representation even in the absence 

of such a submission.

In addition to the flexibility provided by allowing an 

alternate to act for the designated representative (e.g., in 

circumstances where the designated representative might be 

unavailable), additional flexibility would be provided by 

allowing the designated representative and alternate to delegate 

authority to make electronic submissions on his or her behalf.

The designated representative and alternate could designate 

agents to submit electronically certain specified documents. The 
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previously-described requirements for designated representatives 

and alternates would provide regulated entities with flexibility 

in assigning responsibilities under the mass-based trading 

program, while ensuring accountability by owners and operators 

and simplifying the administration of the proposed mass-based 

trading program. 

2. Allowance Tracking and Compliance System 

The mass-based trading program rules would establish the 

procedures and requirements for using and operating the 

Allowance Tracking and Compliance System (which is the 

electronic data system through which the Administrator would 

handle allowance allocation, holding, transfer, and deduction), 

and for determining compliance with the allowance-holding 

requirements in an efficient and transparent manner. The ATCS 

would also provide the allowance markets with a record of 

ownership of allowances, dates of allowance transfers, buyer and 

seller information, and the serial numbers of allowances 

transferred. Consistent with the approach in prior EPAadministered trading programs, allowance price information would 

not be included in the ATCS. The EPA’s experience is that 

private parties (e.g., brokers) are in a better position to 

obtain and disseminate timely, accurate allowance price 

information than is the EPA. For example, because not all 
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allowance transfers are immediately reported to the 

Administrator for recordation, the Administrator would not be 

able to ensure that any reported price information associated 

with the transfers would reflect current market prices.

3. Compliance and General Accounts 

This section describes two types of Allowance Tracking and 

Compliance system accounts: Compliance accounts, one of which 

the Administrator would establish for each facility with an 

affected EGU upon receipt of the certificate of representation 

for the facility; and general accounts, which could be 

established by any entity upon receipt by the Administrator of 

an application for a general account. A compliance account would 

be the account in which any allowances used by an affected EGU

for compliance with the emissions limitations would have to be 

held. The designated representative and alternate for the 

affected EGU would also be the authorized account representative 

and alternate for the compliance account. Using facility-level, 

rather than electric generating unitEGU-level accounts, would 

provide owners and operators more flexibility in managing their 

allowances for compliance, without jeopardizing the 

environmental goals of the mass-based trading program, because 

the facility-level approach would avoid situations where an EGU 

would hold insufficient allowances and would be in violation of 
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allowance-holding requirements even though EGUs at the same 

facility had more than enough allowances to meet these 

requirements for the entire facility. Facility-level compliance 

would also be consistent with other EPA-administered mass-based 

trading programs.

General accounts could be used by any person or group for 

holding or trading allowances. However, allowances could not be 

used for compliance with emissions limitations so long as the 

allowances were held in, and not properly and timely transferred 

out of, a general account. To open a general account, a person 

or group would have to submit an application for a general 

account, which would be similar in many ways to a certificate of 

representation. The application would include, in a format 

prescribed by the Administrator: the name and identifying 

information of the individual who would be the authorized 

account representative and of any individual who would be the 

alternate authorized account representative; an identifying name 

for the account; the names of all persons with an ownership 

interest with respect to allowances held in the account; and 

certification language and signatures of the authorized account 

representative and alternate. The authorized account 

representative and alternate would be authorized upon receipt of 

the application by the Administrator. The provisions for 
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changing the authorized account representative and alternate, 

for changing the application to take account of changes in the 

persons having an ownership interest with respect to allowances, 

and for delegating authority to make electronic submissions 

would be analogous to those applicable to comparable matters for 

designated representatives and alternates. 

4. Recordation of Allowance Allocations and Transfers

By June 1, 2021, the Administrator would record allowance 

allocations for electric generating unitsEGUs for 2022 through 

2024. Then, by June 1 of the year prior to the beginning of each

compliance period, the Administrator would record the allowance 

allocations for the proposed mass-based trading program for each 

year within that next compliance period, e.g., for 2025, 2026, 

and 2027 by June 1, 2024. Recording these allowance allocations 

in advance of the first year for which they could be used for 

compliance would facilitate compliance planning by owners and 

operators and promote robust allowance markets, including 

futures markets for allowances. 

The process for transferring allowances from one account to 

another would be quite simple. A transfer would be submitted 

providing, in a format prescribed by the Administrator, the 

account numbers of the accounts involved, the serial numbers of 

the allowances involved, and the name and signature of the 
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transferring authorized account representative or alternate. If 

the transfer form containing all the required information were 

submitted to the Administrator and, when the Administrator 

attempted to record the transfer, the transferor account 

included the allowances identified in the form, the 

Administrator would record the transfer by moving the allowances 

from the transferor account to the transferee account within 5 

business days of the receipt of the transfer form. 

5. Compliance with Emissions Limitations

Once the compliance period has ended (e.g., at midnight on 

December 31, 2024 for the first compliance period), facilities 

with affected EGUs would have a window of opportunity following 

the compliance period to evaluate their reported emissions and 

obtain any allowances that they might need to cover their 

emissions during the compliance period. For example, the 

allowance transfer deadline for the first compliance period

would be midnight on May 1, 2025 (the EPA is also requesting 

comment on earlier or later allowance transfer deadlines). Each 

allowance issued in the proposed mass-based trading program 

would authorize emission of one ton of CO2 and so would be usable 

for compliance, for the compliance period that includes the year 

for which the allowance was allocated or a later compliance

period. Consequently, each affected EGU would need, as of the 
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allowance transfer deadline, to have in its facility compliance 

account, or to have a properly submitted transfer that would 

move into its compliance account, enough allowances usable for 

compliance to authorize its total emissions for the compliance

period. The authorized account representative could identify 

specific allowances to be deducted, but, in the absence of such 

identification or in the case of a partial identification, the 

Administrator would deduct on a first-in, first-out basis.

Deducting allowances may have tax and accounting implications, 

so having a default deduction method provides the 

representatives with certainty regarding which allowances will 

be deducted for compliance. Allowances that are deducted for 

compliance will remain in the system in an EPA account, which 

ensures they will not be used again. If a facility were to 

fail to hold sufficient allowances for compliance by all 

affected EGUs at the facility, then the owners and operators of 

the facility and each affected EGU at the facility would have to 

provide, for deduction by the Administrator, two allowances 

allocated for the compliance period in the next year for every 

allowance that the owners and operators failed to hold as 

required to cover emissions. This submittal of two times the 

allowances required for the prior period is an ongoing 

obligation until compliance is achieved, and there is an ongoing 
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obligation to comply in the current period. In addition, these

owners and operators would be subject to civil penalties for 

each violation in accordance with the Clean Air ActCAA, with 

each ton of unauthorized emissions and each day of the 

compliance period involved constituting a violation of the CAA.

The EPA believes that it is important to include a 

requirement for an automatic deduction of allowances. The 

deduction of one allowance per allowance that the owners and 

operators failed to hold would offset this failure. The 

automatic deduction of another allowance per allowance that the 

owners and operators failed to hold that could not be avoided, 

regardless of any explanation provided by the owners and 

operators for their failure, would provide a strong incentive 

for compliance with the allowance-holding requirement by 

ensuring that non-compliance would be a significantly more 

expensive option than compliance. Such automatic deductions have 

been successfully used in prior programs including the Clean Air 

Interstate RuleCAIR, achieving compliance rates close to 100 

percent.

6. Other Allowance Tracking and Compliance Operations Provisions

These sections also would provide that the Administrator 

could, at his or her discretion and on his or her own motion, 

correct any type of error that he or she finds in an account in 
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the Allowance Tracking and Compliance System. In addition, the 

Administrator could review any submission under the mass-based 

trading program, make adjustments to the information in the 

submission, and deduct or transfer allowances based on such 

adjusted information. These provisions are a standard part of 

other trading programs administered by the EPA including the 

Acid Rain ProgramARP and Cross State Air Pollution Rule (see 40 

CFR §§72.96, 73.37, 97.427, and 97.428). 

H. Emissions Monitoring and Reporting Requirements

The EPA proposes that units subject to the mass-based 

federal plan trading program would monitor and report CO2 mass 

emissions in accordance with 40 CFR part 75.

The EPA is proposing to require affected EGUs in all states

covered by the mass-based federal plan trading program to 

monitor and report CO2 emissions and output data by January 1, 

2022. Quarterly reporting would be required, with each quarterly 

report due to the Administrator 30 days after the last day in 

the quarter. The reporting would be in accordance with 40 CFR 

part 75.60. The use of part 75 certified monitoring 

methodologies would be required. Many EGUs that might be covered 

by the proposed federal plans will generally have no changes to 

their monitoring and reporting requirements and will continue to 

monitor and submit reports under part 75 as they have under 
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existing programs. The EPA anticipates fewer than 50 affected 

EGUs that would not otherwise be subject to the Acid Rain 

ProgramARP will have to purchase and install additional CEMS and 

data handling systems or upgrade existing equipment in order to 

meet the monitoring and reporting requirements of this program

(the EPA anticipates approximately 10 coal fired units and 

approximately 40 gas and oil fired units will qualify for an 

excepted monitoring methodology). Several of the units not 

otherwise subject to the Acid Rain ProgramARP are subject to the 

MATS program and, therefore, will have already installed stack 

flow rate and/or CO2 monitors necessary to comply with this rule

in order to comply with the MATS. The CEMS used to comply and 

report data for MATS will be used for this rule to generate and 

report CO2 emissions data without having to install duplicative 

monitors. The same CO2 and stack gas flow rate monitored data 

used in conjunction with Hgmercury and other CEMS to calculate a 

toxic pollutant emission rate may be used to calculate a CO2 mass 

or CO2 emission rate for this program. RGGI, ARP, MATS and this 

rule all refer to CEMS installed and certified in accordance 

with 40 CFR part 75. RGGI and ARP currently require the 

reporting of CO2 mass emissions on an hourly basis and cumulative 

totals at the end of each calendar quarter. The same monitors 

and data collected may be used for multiple purposes for RGGI, 
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ARP, MATS and this rule. Relying on the same monitors that are 

certified and quality ensured in accordance with 40 CFR part 75 

ensures cost efficient, consistent, and accurate data that may 

be used for different purposes for multiple regulatory programs.

The majority of the units covered by this rule are already 

affected by the Acid Rain and/or Regional Greenhouse Gas 

InitiativeRGGI programs and will have minimal additional 

monitoring and reporting requirements. 

The EPA also requests comment on requiring monitoring and 

reporting of CO2 mass and net generation for the year before the 

initial compliance period begins, i.e., to commence January 1, 

2021. Only the monitoring and reporting would be required in 

2021 — compliance with the requirement to hold allowances would 

commence on the compliance period schedule that is detailed in 

section V.C of this preamble.

VI. Implementation of the Federal Plan and Delegation

Under section 111(d) of the CAA, the EPA adopts Emission 

Guidelines (EG)EGs that are then implemented when the EPA 

approves a state or tribal121 plan or promulgates a federal plan 

 

121 AS discussed in (citation) tribes with EGU in their areas of 

Indian country can apply for TAS for the purpose of developing and 

seeking EPA approval of a tribal implementation plan (TIP) 
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that implements and enforces the EGEGs for affected EGUS in 

states or areas of Indian country122 without an approved state or 

tribal plan. Congress has determined that the primary 

responsibility for air pollution prevention and control rests 

with state and local agencies, while also recognizing that 

“Federal ... leadership is essential for the development of 

cooperative Federal, State, regional, and local programs to 

prevent and control air pollution.” (See section 101(a)(3) and 

(4) of the CAA.) Congress has also provided for Indian Tribes 

meeting specified eligibility criteria to implement the Clean 

Air ActCAA within the exterior boundaries of their reservations 

or other areas within the tribe’s jurisdiction. (See section 

301(d)(1) and (2) of the CAA.) Even in the event that it becomes 

necessary for the EPA to directly regulate affected EGUS under

CAA section 111(d), states and eligible tribes may still seek a 

delegation of authority from the EPA to implement a federal 

plan, similar to the ability to take delegated authority under 

other CAA programs. The EPA encourages states and eligible 

tribes that do not submit approvable plans to request delegation 

 

implementing the EG, but are not required to do so.

122 As discussed in detail in (citation), in adopting a federal 

plan implementing the EGs in areas of Indian country containing 

EGU, the EPA must determine that such a plan is “necessary or 

appropriate” to protect air quality. See, 40 CFR 49.11(a).
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of the federal plan if they wish to have primary responsibility 

for implementing the EG. Approved and effective state or tribal 

plans or delegation of the federal plan is the EPA’s preferred 

outcome in many circumstances where the EPA believes that state 

and local, or tribal, agencies have practical knowledge and 

enforcement resources critical to achieving the highest rate of 

compliance. Legally, delegation of a standard or requirement 

means that obligations a source may have to the EPA under a 

federally promulgated standard become obligations to a state or 

tribe (except for functions that the EPA retains for itself) 

upon delegation.123 124

A. Delegation of the Federal Plan and Retained Authorities

If a state or tribe125 intends to take delegation of the 

 

123 If the Administrator chooses to retain certain authorities 

under a standard, those authorities cannot be delegated, e.g., 

the authority to allow alternative methods of demonstrating 

compliance.

124 We note that issuance of a title V permit is not equivalent to 

the approval of a state plan or delegation of a federal plan. This 

has been discussed in prior rulemakings, see, e.g., Proposed 

Federal Plan for Commercial Industrial Solid Waste Incinerators 

(CISWI) (67 FR 70640, 70652; Nov. 25, 2002); Final Federal Plan 

for CISWI (68 FR 57518, 57535; Oct. 3, 2003).

125 A tribe interested in taking delegation of the federal plan 

must also apply, and be approved by the EPA, for TAS eligibility 

for that purpose. 40 CFR part 49.
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federal plan, the state or tribe should submit to the 

appropriate EPA Regional Office a written request for delegation 

of authority. The state or tribe should explain how it meets the 

criteria for delegation. See generally “Good Practices Manual 

for Delegation of NSPS and NESHAP” (EPA, February 1983). The 

letter requesting delegation of authority to implement the 

federal plan should: (1) Demonstrate that the state or tribe has 

adequate resources, as well as the legal and enforcement 

authority to administer and enforce the program, (2) include an 

inventory of affected EGUs, which includes those that have 

ceased operation but have not been dismantled, include an 

inventory of the affected units’ air emissions and a provision 

for state or tribal progress reports to the EPA, (3) certify 

that a public hearing has been held on the state or tribal 

delegation request, and (4) include a memorandum of agreement 

between the state or tribe and the EPA that sets forth the terms 

and conditions of the delegation, the effective date of the 

agreement and the mechanism to transfer authority. Upon 

signature of the agreement, the appropriate EPA Regional Office 

would publish an approval notice in the Federal Register, 

thereby incorporating the delegation of authority into the 

appropriate subpart of 40 CFR part 62. See also EPA’s 

Delegations Manual, Delegation 7-139, “Implementation and 
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Enforcement of 111(d)(2) and 111(d)(2)/129(b)(3) federal plans.” 

(A copy of this delegation manual has been placed in the docket 

for this action.)

If authority is not delegated to a state or tribe, the EPA 

will implement the federal plan. Also, if a state or tribe fails 

to properly implement a delegated portion of the federal plan, 

the EPA will assume direct implementation and enforcement of 

that portion. The EPA will continue to hold inspection, 

information gathering, enforcement, and other parallel 

authorities along with the state or tribe even when a state or 

tribe has received delegation of the federal plan. In all cases 

where the federal plan is delegated, the EPA willmay retain and 

will not transfer authority to a state or tribe to approve the 

followingcertain items promulgated in the 2015 CAA section 

111(d) Clean Power Plan:.

(1) [&&& DO WE HAVE A LIST OF ITEMS FOR WHICH EPA 

PREFERS TO MAINTAIN AUTHORITY?]

Today’sThis proposed federal plan also specifies that EGU 

owners or operators who wish to petition the agency for any 

alternative requirement should submit a request to the Regional 

Administrator with a copy set to the appropriate state.
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B. Mechanisms for Transferring Authority

There are two mechanisms for transferring implementation 

authority to state and local agencies and tribes: (1) The EPA 

approval of a state or tribal plan after the federal plan is in 

effect; and (2) if a state or tribe does not submit or obtain 

approval of its own plan, the EPA delegation to a state or tribe 

of the authority to implement certain portions of this federal 

plan to the extent appropriate and if allowed by state or tribal 

law. Both of these options are described in more detail below.

1. Federal Plan Becomes Effective Prior to Approval of a State or 

Tribal Plan

After EGUs in a state or area of Indian country become 

subject to the federal plan, the state or local agency or tribe 

may still adopt and submit a plan to the EPA. If the EPA 

determines that the state or tribal plan is satisfactory and 

approvable pursuant to the EG, the EPA will approve the state or 

tribal plan. If the EPA, on review of the submitted state or 

tribal plan, determines that this is not the case, the EPA will 

disapprove the plan and the EGUs covered in the state or tribal 

plan would remain subject to the federal plan until a state or 

tribal plan covering those EGU is approved and effective. Prior 

to disapproval, the EPA will work with states and eligible 
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tribes to attempt to reconcile areas of the plan that are 

unapprovable. 

Upon the effective date of an approved state or tribal 

plan, the federal plan would no longer apply to EGUs covered by 

such a plan and the state or local agency, or the tribe, would 

implement and enforce the state or tribal plan in lieu of the 

federal plan. The timing of effectiveness of an approved state 

or tribal plan in this circumstance may depend in part on the 

need to ensure a smooth transition and maintain regulatory 

certainty. Thus, for example, under a mass-based federal plan, 

we propose to handle these transitions so that they coincide 

with the compliance periods. The approval of a state or tribal 

plan would also involve a public comment process, which would 

give interested stakeholders including any affected EGUs, the 

opportunity to comment. This will assist in ensuring that 

compliance, program integrity, electric reliability, and other 

critical factors are maintained. When an EPA Regional Office 

approves a state or tribal plan, it will amend the appropriate 

subpart of 40 CFR part 62 or 40 CFR part 49, respectively, to 

indicate such approval, as well as the timing of its 

effectiveness.

As discussed elsewhere in this Noticedocument, the EPA may 

also in certain circumstances approve a partial state or tribal 
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plan (sometimes called an “abbreviated state plan”) that may 

modify certain limited provisions in the federal plan trading 

program. For example, this could occur if a state or tribe 

wishes to handle the initial allocation of allowances in a massbased trading program, as discussed in section &&& above.V.E of 

this preamble. The partial state or tribal plan would allow for 

the state or tribe to assume direct authority for administering 

and implementing this aspect of the trading program, while the 

remainder of the federal plan remains in place. The procedural 

and submission requirements set forth in the framework 

regulations of 40 CFR part 60, subpart B and the EGEGs would 

generally apply to a partial state or tribal plan, just as they 

would a full state or tribal plan. The scope of the requirement, 

however, would be commensurate with the scope of the partial 

plan. For instance, if a state or tribe seeks approval of a 

partial plan solely to handle allowance allocations, then the 

required statement of legal authority would be limited to those 

legal authorities the state or tribe must have to implement and 

enforce this component of the trading program.

2. State or Tribe Takes Delegation of the Federal Flan

The EPA, in its discretion, may delegate to state or tribal 

air agencies the authority to implement this federal plan. As 
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discussed above, the EPA believes that it is advantageous and 

the best use of resources for state or local agencies or tribes 

to agree to undertake, on the EPA’s behalf, administrative and 

substantive roles in implementing the federal plan to the extent 

appropriate and where authorized by state or tribal law. If a 

state or tribe requests delegation, the EPA will generally 

delegate the entire federal plan to the state or tribal agency, 

thereby providing authority to the state or tribe for things 

such as administration and oversight of compliance reporting and 

recordkeeping requirements, inspections of its affected EGUs, 

and enforcement. The EPA will continue to hold inspection, 

information gathering, enforcement, and other authorities along 

with the state or tribe even when a state or tribe has received 

delegation of the federal plan. The delegation will not include 

any authorities retained by the EPA.

C. Implementing Authority

The EPA Regional Administrators have been delegated the 

authority for implementing the federal plan. All reports 

required by the federal plan should be submitted to the 

appropriate Regional Administrator. Section II.C.B of this 

preamble includes Table [&&&]2 of this preamble that lists names 

and addresses of the EPA Regional Office contacts and the states 
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they cover.

With respect to the administration of a federal trading 

program in any final federal plan for a state or tribe, group of 

states or combined group of states and tribes, the Office of Air 

and Radiation within the Headquarters of the EPA is proposed to 

be the primary office within the agency with delegated CAA 

section 111(d)(2) authority. See Delegation 7-139, section 3(c). 

D. Necessary or Appropriate Finding for Affected EGUs in Indian 

Country

Indian Tribes may, but are not required to, submit tribal 

plans to implement the Emission Guidelines (EG).EGs. Section 

301(d) of the Clean Air ActCAA and 40 CFR part 49 authorize the 

Administrator to treat an Indian Tribe in the same manner as a 

state (TAS) for purposes of developing and implementing a tribal 

plan implementing the EG. See 40 CFR 49.3; see also ‘‘“Indian 

Tribes: Air Quality Planning and Management,’’,” hereafter 

‘‘“Tribal Authority Rule,’’,” (63 FR 7254, February 12, 1998). 

We invite tribes with EGU in their area of Indian country to 

comment on the level of their interest, if any, in developing 

their own plans. 

The EPA is proposing in today’sthis action to find that it 

is necessary or appropriate to regulate affected EGUs in each of 

the three areas of Indian country that have affected EGUs under 
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the proposed federal plan. The EPA is authorized to directly 

implement the EGEGs in Indian country when it finds, consistent 

with the authority of CAA section 301 which the EPA has 

exercised in 40 CFR 49.11, that it is necessary or appropriate 

to do so. In the final Emission GuidelinesEGs, the EPA 

finalizedestablishes emission performance goalsrates for the 

four facilitiesEGUs located in Indian country and mass and ratebased emission goals for each of the three affected areas of 

Indian country with affected EGUs:. These areas include lands of 

the Navajo Nation’s reservation, lands of the Ute Tribe of the 

Uintah and Ouray Reservation, and lands of the Fort Mojave 

Tribe’s reservation. [&&&citation to final EGs]. The EPA 

proposed carbon pollution emission guidelinesEGs for EGUs in 

these areas and U.S. Territories in a Supplemental Notice of 

Proposed Rulemaking. See 79 FR 65482 (Nov. 4, 2014). The four 

facilities with affected EGUs located in Indian country that the 

EPA identified in the Supplemental Notice are: the South Point 

Energy Center, on the Fort Mojave Reservation geographically 

located within Arizona; the Navajo Generating Station, on the 

Navajo Indian Reservation geographically located within Arizona; 

the Four Corners Power Plant, on the Navajo Indian Reservation 

geographically located within New Mexico; and the Bonanza Power 

Plant, on the Uintah and Ouray Indian Reservation geographically 
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located within Utah. The emission performance targets for these 

areas were finalized along with those for EGU located in the 

rest of the country in the final EGs. &&&citation. 

In today’sthis action, we are proposing to find that it is 

necessary or appropriate, in each of the three areas of Indian 

country that have affected EGUs, to establish a federal plan that 

applies to the four power plants located on the Navajo Nation, the 

Fort Mojave Indian Reservation, and the Uintah and Ouray 

Reservation of the Ute Tribe. The affected EGUs located on the 

Navajo Nation are in an area of Indian country located within the 

continental United States,U.S., are interconnected with the 

western electricity grid, and are owned and operated by entities 

that generate and provide electricity to customers in several 

states. The affected EGU located on the Uintah and Ouray 

Reservation of the Ute Tribe is in an area of Indian country 

located within the continental United States,U.S., is 

interconnected with the western electricity grid, and is owned and 

operated by an entity that generates and provides electricity to 

customers in several states. The affected EGU located on the Fort 

Mojave Indian Reservation is in an area of Indian country located 

within the continental United States,U.S., is interconnected with 

the western electricity grid, and is owned and operated by an 

entity that generates and provides electricity to customers in 
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several states. To date, none of the three tribes on whose areas 

of Indian country the four power plants are located have expressed 

a clear intent to develop and seek approval of a tribal 

implementation plan. Thus, absent a federal plan, the significant 

emissions from these four power plants could go unregulated by the 

Clean Power Plan.

Because the agency has finalized emission performance targets 

for these power plants in the EGs, there is, in our view, little 

benefit to be had by not proposing to include them in a federal 

plan now and a potentially significant downside to not doing so; 

the reductions the EPA has determined are achievable in the EGs 

would become more difficult and costly for these power plants to 

achieve if they are delayed in entering into the trading program 

the agency intends to establish. In order to meet the performance 

targets, we are anticipating that the affected EGUs may need to 

secure allowances or ERCs (depending on the approach ultimately 

finalized) during the compliance periods. They may also be able to 

generate and sell compliance instruments by participating in the 

trading program. Thus, proposing a finding that it is necessary or 

appropriate to establish one or more federal plans providing the 

ability to participate in a rate- or mass-based trading program is 

in the interest of these four power plants located in areas of 

Indian country. We believe that this together with the facts that, 
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as indicated above, all four EGU are interconnected with the 

western electricity grid and are owned and operated by an entity 

that generates and provides electricity to customers in several 

states thereby making it potentially disruptive and inequitable 

not to include them in one or more federal plans on the same 

schedule as other affected EGU strongly supports proposing to find 

that it is necessary or appropriate to establish one or more 

applicable federal plans at this time.

We recognize that the governments of these tribes may still 

choose to seek TAS to develop a tribal plan, and this proposed

determination does not preclude the tribes from taking such 

actions. We also note that this proposed determination does not 

preclude these tribes from seeking TAS and receiving delegation to 

administer aspects of any applicable federal plan that is 

ultimately promulgated. In the event a federal plan is needed, 

proposing a necessary or appropriate finding at this time will 

allow the EPA to expeditiously promulgate a final federal plan for 

one or all of these power plants in the future to allow trading to 

occur. We will continue to consult with the governments of the 

Navajo Nation, Fort Mojave Indian Tribe, and the Ute Tribe of the 

Uintah and Ouray Reservation during the comment period for this 

proposal, and prior to taking any action to finalize a necessary 

or appropriate finding and/or a federal plan. Comments on the 
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appropriateness of the proposed finding, should be submitted 

within the comment period specified in the Dates section of this 

preamble.

VII. Amendments to Process for Submittal and Approval of State 

Plans and EPA Actions 

As indicated in the final rulemaking notice for the CAA 

section 111(d) guideline, “Carbon Pollution Emission Guidelines 

for Existing Stationary Sources: Electric Utility Generating 

Units,” in this action, in addition to the proposed federal 

plans and model trading rules, the EPA is also proposing to 

amend the framework regulations and update the process for 

acting on CAA section 111(d) state plans under Subpart B of 40 

CFR part 60, subpart B. These changes would be applicable to any 

future CAA section 111(d) rules going forward, not just the 

Clean Power Plan EGs. The EPA proposes six changes to the CAA 

section 111(d) process in the framework regulations to include: 

(1) Partial approval/disapproval mechanisms similar to CAA 

section 110(k)(3); (2) a conditional approval mechanism similar 

to CAA section 110(k)(4); (3) a mechanism for the EPA to make 

calls for plan revisions similar to the "SIP-call" provisions of 

CAA section 110(k)(5); (4) an error correction mechanism similar 

to CAA section 110(k)(6); (5) completeness criteria and a 

process for determining completeness of state plans and 
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submittals similar to CAA section 110(k)(1) and (2); and (6) 

updates to the deadlines for the EPA action. In addition, in 

this section, the agency is proposing an interpretation 

regarding the effect under section 111 if an existing facility 

subject to CAA section 111(d) modifies or reconstructs. We 

believe these changes will significantly streamline the state 

plan review and approval process, be more respectful of state 

processes, and generally enhance the administration of the 111d 

program.

Section 111(d)(1) provides that the EPA “shall establish a 

procedure similar to that provided by CAA section [110] of this 

title under which each state shall submit to the Administrator a 

[111(d)] plan . . ..” 42 U.S.C. 7411(d)(1). Thus, the CAA 

directs the EPA to look to the structure of the SIP program when 

designing the procedures the states and agency will use to 

develop CAA section 111(d) plans. Notably, the CAA does not 

require the CAA section 111(d) procedures to be identical to 

those the EPA uses under CAA section 110 for SIPs.126 Therefore, 

the EPA interprets CAA section 111(d) to provide the EPA 

flexibility in designing procedures that reflect the structure 

 

126 See Webster’s II New Riverside University Dictionary (Riverside 

1988) (defining “similar” to mean “resembling though not 

completely identical”).
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of those used under CAA section 110 for implementation plans, 

without requiring the EPA to exactly track SIP procedures when 

acting on section 111(d) plans.

As a general matter these proposed changes would simply 

update the CAA section 111(d) framework regulations to include 

several new, more flexible procedural tools that Congress 

introduced into section 110 in the 1990 Clean Air ActCAA

Amendments. The basic procedures in the CAA section 111(d) 

framework regulations were promulgated in 1975 based on the 

structure of CAA section 110 as Congress designed it in the 1970 

CAA Amendments. See 40 FR 53340-49 (Nov. 17, 1975). Over the 

years since 1970, the EPA and the states learned a great deal 

about the procedural limitations of the original SIP review 

process. The 1970 CAA only allowed the EPA to approve or 

disapprove SIP submittals. The agency struggled to deal 

responsively to situations where the EPA wanted to work with 

states to get state programs approved to the extent possible, 

while maintaining consistency with CAA requirements. Congress 

responded in 1990 and enhanced the procedural mechanisms the EPA 

has to act on SIPs. The EPA is proposing correspondingly to 

update the CAA section 111(d) regulations in a similar fashion. 

Currently, the EPA’s framework regulations for submittal and 

adoption of CAA section 111(d) state plans do not explicitly 
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provide for the EPA to use some of the same procedures for 

approving or disapproving state plans Congress introduced into 

the SIP program in the 1990 Clean Air ActCAA Amendments. The EPA 

is proposing to amend the procedures for approval or disapproval 

of CAA section 111(d) state plans to reflect the enhancements 

Congress included in CAA section 110 for agency actions on SIPs.

These proposed amendments are discussed in more detail below.

A. Partial Approvals/Disapprovals

First, the EPA proposes to add authority similar to that 

under CAA section 110(k)(3) to partially approve or disapprove a 

plan.127 This is a particularly useful function when much of a 

state plan is approvable and the EPA and the state cannot reach 

resolution on only a small, severable portion of the state plan. 

In this case, the EPA prefers not to be in a position where it 

must disapprove the full plan, but rather to allow the state to 

move forward with those portions of the plan that are 

 

127 We recognize that the regulations appear to already contemplate 

partial approval/disapprovals to some extent. See 40 CFR 60.27(a) 

(“The Administrator may ... extend the period for submission of any 

plan ... or portion thereof.”) (emphasis added). We note that this 

language only allows for extensions of time with respect to 

portions of state plan submissions and may not sufficiently 

authorize a permanent partial approval. The proposed enhancement 

will resolve any ambiguity that partial approvals/disapprovals are 

an acceptable mechanism under CAA section 111(d).
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approvableThisapprovable. This mechanism are those situations 

where the state wishes to take over a discrete part of a federal 

plan. For instance, in this proposal, states will be able to 

seek approval of a partial state plan that will give them the 

ability to handle the allocation of allowances under a massbased federal plan.

In cases where elements of a plan are functionally 

severable from each other, and one element is approvable while 

another is not, this provision will authorize the EPA to approve 

one part of a plan and disapprove the other. It will also 

authorize the EPA to accept and review a state plan that is only 

partial in nature, if identified by the state as such, so long 

as the other applicable submission requirements are met (such as 

demonstration of legal authority and completion of the public 

process). When the state submits what it intends to be a full 

state plan (rather than just a partial plan), the EPA proposes 

that the approvable portion of a plan must be functionally 

severable from the rest of the plan, and this will be the case

when the following conditions are met. First, the approvable 

portion of the plan must not depend on the rest of the plan. In 

other words, the disapproval of the remaining portion of the 

plan must not affect the portion that is approved. Second, 

approval of the approvable portion must not alter the function 
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of the submittal in a way that is contrary to the state’s 

intent.

The partial disapproval would be a disapproval for the 

purposes of CAA section 111(d)(2)(A) and would trigger the EPA’s 

authority to issue a federal plan for the state, at least for 

that part of the plan that was disapproved. Incorporating this 

mechanism under the framework regulations for CAA section 111(d) 

will enable the EPA to approve a state to implement as much of 

its program as is consistent with a CAA section 111(d) guideline 

and may reduce the scope of any federal plan that would be 

necessary.

B. Conditional Approvals

The second mechanism is the authority under CAA section 

110(k)(4) to conditionally approve a plan. Where a state has 

submitted a plan that substantially meets the requirements of a 

CAA section 111(d) emission guideline, but requires some 

specific amendments to make it fully approvable, this provision 

authorizes the EPA to conditionally approve the plan. The 

Governor or her designee must submit to the EPA a commitment 

that specifies the amendments to be adopted and submitted to the 

EPA by no later than one1 year from the effective date of the 

conditional approval. If the state fails to meet its commitment, 

the conditional approval is treated as a disapproval. 
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Incorporating this mechanism under the framework regulations for 

CAA section 111(d) will enable the EPA to approve a state to 

begin to administer a substantially complete program that 

requires only specific changes to be fully approvable. For 

example, in this action, we are proposing to conditionally 

approve state plans that adopt the proposed model trading rule, 

so long as the state commits to adopt any changes in the final 

model trading rule necessary to ensure EG requirements are met. 

This provision is designed to authorize a state with a 

substantially complete and approvable program to begin 

implementing it, while promptly amending the program to ensure 

it fully complies with CAA section 111(d).

C. Calls for Plan Revisions 

CAA section 110(k)(5) authorizes the EPA to find that a

state implementation planSIP does not comply with the 

requirements of the CAA. To date, the EPA has not considered 

using a similar procedure pursuant to the authority under CAA 

section 111(d). We now propose to do so. The ability to call for 

plan revisions is fundamental to a program that will be 

implemented over many years multiple decadUnder the Clean Power 

Plan EGs, states have more than a decade to fully implement 

emissions standards or state measures in order to ensure 

affected EGUs achieve the emission goals of the EGs. Throughout 
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this period, the EPA and the states will be monitoring their 

programs to ensure they are achieving the intended results. It 

is possible that design assumptions about the effect of control 

measures the states incorporate into their plans could prove 

inaccurate in retrospect and could result over time in the plan 

not meeting the emissions reductions required by the EGs. In 

that case, having a procedural mechanism available under CAA

section 111(d) similar to the so-called “SIP call” mechanism in

CAA section 110(k)(5) will allow the agency to initiate a 

process with the state to make necessary revisions to ensure the 

plan functions properly. 

Accordingly, the EPA is proposing to amend the framework 

regulations to include a provision similar to CAA section 

110(k)(5) under which the EPA may find that a state’s CAA 

section 111(d) plan is substantially inadequate to comply with 

the requirements of the CAA and require the state to revise the 

plan as necessary to correct such inadequacies. Consistent with

CAA section 110(k)(5), the EPA shall notify the state of any 

inadequacies and establish a reasonable deadline for the state 

to submit required plan revisions. That deadline will not exceed 

18 months after the date of the notice. The EPA will make its 
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finding and notice to the state available to the public.128

The effect of such a finding is that either the state 

submits the program corrections by the date the EPA sets in the 

notice, or pursuant to CAA section 111(d)(2)(A), the EPA has 

authority to issue a federal plan for a state that misses its 

deadline to correct its plan. In effect, the finding of plan 

inadequacy establishes a plan submittal deadline subject to the 

provisions of CAA section 111(d)(2)(A). A finding of failure to 

meet that new deadline triggers the EPA’s authority to issue a 

federal plan for the state. The EPA may promulgate a federal 

plan at any time following the state’s failure to timely submit 

an adequate plan that addresses the EPA’s finding.

While these authorities are important, the intention of 

having a mechanism to call for plan revisions is to have a way 

to initiate an orderly process to improve plans when they are 

not meeting program objectives. It is the EPA’s hope that a call 

for plan revision leads to a constructive dialogue with a state 

or states, and ultimately, an improved and more effective CAA 

section 111(d) plan.

The EPA is also proposing that the agency can call for a 

 

128 Consistent with the agency’s practice under CAA section 

110(k)(5), the EPA anticipates that a call for plan revisions under 

CAA section 111(d) will be done via notice and comment rulemaking.
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plan revision in circumstances where a state is not implementing 

its approved state plan and, therefore, the state plan is 

substantially inadequate to provide for the implementation of 

CAA section 111(d) standards of performance. As discussed above, 

the ActCAA directs the EPA to develop a procedure for state 

plans under CAA section 111(d) similar to CAA section 110 SIP 

procedures. Calling a plan that is substantially inadequate to 

provide for implementation of standards of performance (i.e.,

there is a failure to implement a state plan) is one area where 

the EPA proposes it is appropriate to adapt the procedural 

mechanisms available in the SIP program to provide a similar 

process that assures effective state plan implementation under 

CAA section 111(d). Under CAA section 110(k)(5), the EPA may 

call for a revision of a state plan “[w]henever the 

Administrator finds that the . . . plan . . . is substantially 

inadequate to . . . comply with any requirement of [the Act].”

If the state does not submit a plan revision in response to the 

call to cure the failure to provide for implementation, the EPA 

would have the authority to promulgate the federal plan being 

proposed.

One critical requirement of CAA section 111(d)(1)(B) is 

that a state must submit a plan that “provides for the 

implementation and enforcement of such standards of performance” 
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(emphasis added). If, after the EPA has approved a plan, a state 

fails to implement that plan, the plan has become substantially 

inadequate to comply with this requirement of the ActCAA. Under 

this proposal, the EPA’s remedy would be to find the plan is 

substantially inadequate, which triggers the state’s obligation 

to cure, and failing that, the EPA’s authority to promulgate the 

federal plan.

In the alternative, the EPA proposes that this authority to 

call a plan for failure to implement is anchored in the 

authority provided under CAA section 110(k)(5) to call a SIP 

when the agency finds that it is “substantially inadequate to 

attain or maintain the relevant national ambient air quality 

standard.” In the context of CAA section 111, this authority 

translates into the EPA calling a state plan when the agency 

finds that it is substantially inadequate to achieve the 

emissions reductions required under the EG. If a state has 

failed to implement its plan, and that failure is pervasive 

enough to render the requirements of the plan ineffective, it is 

reasonable for the EPA to find that the state plan is 

substantially inadequate to achieve the emissions reductions 

required under the EG. The state’s failure to implement has 

revised the effect of the plan so that it is no longer adequate 

to meet the Act’sCAA’s requirements.Error Corrections
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Error Corrections

The fourth mechanism is the error correction authority 

under CAA section 110(k)(6). Where the EPA concludes that it has 

erroneously approved, disapproved, or promulgated a plan or plan 

revision (or part thereof), this section authorizes the agency 

to revise its action, in the same manner as the original action, 

without requiring any further submission from the state. Prior 

to the 1990 CAA Amendments, there was some question whether the 

EPA could unilaterally correct a previous action on a SIP 

submittal without the state having to submit a new SIP. This 

limitation imposed unnecessary burdens on states to fix even 

obvious errors, because CAA section 110(a)(2) requires the state 

to provide notice and a public hearing on each new SIP 

submittal. Incorporating this mechanism into the CAA section

111(d) framework regulations will allow the EPA to fix errors in 

its prior actions on state plans without imposing on the states 

the corresponding burden of providing notice and a public 

hearing as required under the CAA section 111(d) framework 

regulations. 40 CFR 60.23.

D. Completeness Criteria

Completeness criteria provide the agency with a means to 

determine whether a submission by a state includes the minimum 

elements that must be met before the EPA is required to act on 
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such submission. When submittals do not contain the necessary 

minimum elements, then the EPA may, without further action, find 

that a state has failed to submit a plan. This determination 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 sufficiency or adequacy of the submitted portions of a state 

plan. The task is accomplished by simply comparing the materials 

provided by the state as its submittal against the required 

criteria to determine whether the plan is complete or not. In 

the case of SIPs under CAA section 110(k)(1), the EPA 

promulgated completeness criteria in 1990 at appendix V to 40 

CFR part 51 (55 FR 5830; Feb. 16, 1990). The 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). The completeness criteria can be grouped 

into: (1) Administrative materials; and (2) technical support. 

The EPA proposes that both groups would apply to all CAA section 

111(d) rules going forward. The agency notes that the addition 

of completeness criteria in the framework regulations does not 

alter any of the submission requirements states already have 

under the EGs. 

For administrative materials, the EPA is proposing 

completeness criteria that mirror the existing administrative 
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criteria for SIP submittals because the two programs have 

similar administrative processes. The EPA proposes that a 

complete final state plan submittal under CAA section 111(d)

must include: (1) A formal letter of submittal from the Governor 

or her 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 shall 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; and 

(4) a copy of the actual regulation, or document submitted for 

approval and incorporation by reference into the plan. The 

submittal shall be a copy of the official state 

regulation/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/document shall, 

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 shall 

indicate the changes made (for example, by 

redline/strikethrough) to the approved plan; (5) evidence that 

the state followed all of the procedural requirements of the 
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state's laws and constitution in conducting and completing the 

adoption/issuance of the plan; (6) evidence that public notice 

was given of the proposed change 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; and (8) compilation of public comments and the 

state's response thereto.

These criteria, as proposed, are intended to be generic to all 

CAA section 111(d) plans going forward, with the proviso that 

specific emission guidelinesEGs may provide otherwise. The 

technical support completeness criteria that the EPA proposes 

will also be generic to all CAA section 111(d) rules, with the 

same proviso. The EPA proposes that 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 the designated facilties, 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)
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demonstration that the state plan submittal is projected to 

achieve emissions performance under the applicable EGs; (5) 

documentation of state recordkeeping and reporting requirements 

to determine the performance of the plan as a whole; and (6) 

demonstration that each emission standard is quantifiable, nonduplicative, permanent, verifiable, and enforceable.

The EPA proposes a process similar, though not identical, 

to that set forth in 40 CFR 51.103 and Appendix V to 40 CFR part 

51 to make completeness determinations. Similar to CAA section 

110(k)(1)(C), under this proposal, where the EPA determines that 

a state submission required under CAA section 111(d) does not 

meet the minimum completeness criteria we are proposing to 

establish, the state will be considered to have not made the 

submission. The EPA further proposes that, similar to CAA

section 110(k)(1)(B), within 60 days of the EPA'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 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. 
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As with the completeness determination process for SIP 

submissions, the EPA’s determination that a submittal is 

complete is not a finding that the submittal meets the 

substantive requirements of CAA section 111(d) or the guideline. 

That must be done via the process for approval or disapproval of 

a state plan, which would be done through notice and comment 

rulemaking. In the completeness process, the EPA will confirm 

that a state’s submittal appears to have addressed the criteria 

for a complete submittal and, therefore, the submittal is 

sufficient to trigger the EPA’s obligation to act on it. But in 

the completeness process the agency will not assess the content 

of those submissions to determine if they are approvable. 

Accordingly, even when the EPA affirmatively determines that a 

submittal is complete, it does not prevent the agency from later 

finding that the state plan does not meet the requirements of 

the EGs, including finding that the submittal failed to address 

a required element and must be disapproved.

Similarly, when a submittal is determined to be complete by 

operation of law after six6 months without the EPA’s affirmative 

determination of completeness, the only legal consequence is 

that the EPA now has an obligation to act on that submittal. 

Completeness by operation of law means that the submittal is 

deemed complete and requires the EPA’s review, whether or not 
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the state has actually addressed all the required elements.

Accordingly, if the agency determines that a state has failed to 

address a required element in its submittal once the EPA begins 

review of the state plan that is complete by operation of law, 

the agency must go through the process of disapproving (or 

partially disapproving or conditionally approving, as discussed 

below) that plan, unless the state and the EPA work together to 

cure the deficiency. In other words, the EPA cannot simply find 

the plan incomplete and return it to the state at that point. 

But the finding of completeness by operation of law in no way 

prevents the EPA from subsequently concluding that the state’s 

submission is missing a required element of the program and 

making that finding as part of a disapproval of the plan.

As described in the final rulemaking notice for the CAA 

section 111(d) EGs, a state will submit all CAA section 111(d) 

plans electronically. If the EPA determines that any submission 

fails to meet the completeness criteria, the agency may return 

the plan to the state and request corrections, identifying the 

components that are absent or insufficient to allow the EPA to 

perform a review of the plan. The state will not have met its 

obligation to submit a final plan until it resubmits a revised 

state plan or supporting materials addressing the corrections 

the EPA identified in its incompleteness determination.
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The EPA is also proposing to include an exception to the 

criteria for complete administrative materials in cases where a 

state and the EPA are “parallel processing” the final plan. 

Parallel processing allows a state to submit the plan prior to 

final adoption by the state and provides an opportunity for the 

state to consider the EPA’s comments prior to submission of a 

final plan for final review and action. The EPA would propose to 

take action on a state plan based on a proposed state 

regulation. The EPA would only finalize the action if the state 

adopts a final plan that is legally effective under state law. 

The EPA would only approve the plan if the state addressed any 

corrections that the EPA identified in its proposed action on 

the state plan without any other material change to the plan. In 

this scenario, the state’s initial submittal would not be able 

to meet all the criteria for administrative completeness, and 

the EPA proposes to adjust those criteria as provided for in 40 

CFR Pt. 51, App. V section 2.3. Note that a plan submitted for 

parallel processing must still meet all the criteria for 

technical completeness so that the EPA and the public have a 

sufficient basis on which to evaluate and comment on the EPA’s 

proposed action.

Finally, the EPA proposes that, in the case of an initial 

submittal under the Clean Power Plan EGs, the requirements set 
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out at Part &&&60.5760, shall serve as the completeness criteria 

the EPA will use to determine whether the initial submittal is 

complete. If those minimal submission requirements have not been 

met, as determined by the EPA in accordance with &&&60.5760(b), 

then the state will be treated as having failed to submit a 

state plan. 

E. Update to Deadlines for EPA Actions

The EPA proposes to update the deadlines for acting on 

state submittals and promulgating a federal plan under 40 CFR 

60.27(b), (c), and (d) to more closely track the current 

versions of CAA section 110(c) and 110(k) adopted in 1990. The 

framework regulations for CAA section 111(d) state plans 

currently are parallel to the prior version of CAA section 110. 

They require the EPA to act on a state plan or plan revision 

submittal within 4 months after the date required for submission 

of a plan or plan revision. 40 CFR 60.27(b). The regulations 

then require the EPA to issue a proposed federal plan in certain 

circumstances after consideration of any state hearing record, 

40 CFR 60.27(c), and require the EPA to promulgate the proposed 

federal plan within 6 months after the date required for plan 

submissions, id. 60.27(d). 

The final carbon dioxide EGsCO2 EG for Electric Utility 

Generating Units (EGUs) have already adjusted the deadline in 
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60.27(b) to require the EPA to act on a state plan under those 

EGs within 12 months (rather than 4 months) after the date 

required for submission of a plan. See 40 CFR 60.5715. However, 

the Clean Power Plan EGs did not modify the 6 month deadline for 

a federal plan in 60.27(d).

The EPA is proposing to amend 40 CFR 60.27(b) to allow the 

EPA 12 months to approve or disapprove submittals of all plans 

or plan revisions under CAA section 111(d), not just those 

related to the Clean Power Plan under 60.5715. This change would 

provide the EPA with sufficient time for the steps 

Fdrequiredrequired to approve or disapprove the submittal, which 

include proposing the EPA’s approval or disapproval of the plan 

or plan revision, a public comment period on the EPA’s proposal, 

time for the EPA to review and respond to public comments, and 

the issuance of a final rule approving or disapproving the plan 

or plan revision.

The EPA is also proposing to amend 40 CFR 60.27(b) to 

specify that the deadline for the EPA to act on a plan or plan 

revision is 12 months after receipt of a complete plan or plan 

revision, rather than 12 months after the deadline for submittal 

of a plan or plan revision. This amendment will allow the EPA to 

have the full 12 months to act on submittals of complete plans 

or plan revisions. 
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The EPA also proposes slight modifications to the provision 

related to issuing a proposed federal plan in 60.27(c); changing 

the six6 month deadline for issuing a final federal plan in 

60.27(d) to one1 year129; and, similar to the change in timing 

for 60.27(b) above, setting the deadline for promulgation of a 

federal plan to run from the date of the EPA's action on a state 

submittal, rather than from the original deadline for a state 

submittal.

The EPA believes it is appropriate to modify these timing 

requirements for several reasons. First, the EPA notes that 

under CAA section 111(d)(2), Congress gave the EPA the "same" 

authority to prescribe a federal plan under CAA section 111(d) 

as it would have under CAA section 110(c) in the case of a state 

failure to submit a SIP. The term "same" stands in contrast to 

the term "similar" in CAA section 111(d)(1) (discussed above). 

 

129 As under CAA section 110, the EPA believes that, should it fail 

for whatever reason to meet a deadline by which it was to take 

action, such as issue a federal plan, under CAA section 111(d), 

that failure does not thereby obviate or in any way remove the 

EPA’s authority or obligation to take that action. See Oklahoma v. 

U.S. EPA, 723 F.3d 1201, 1224 (10th Cir. 2013) (“Although the 

statute undoubtedly requires that the EPA promulgate a FIP within 

two years, it does not stand to reason that it loses its ability 

to do so after this two-year period expires. Rather, the 

appropriate remedy when the EPA violates the statute is an order 

compelling agency action.”).
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As with the use of the term “similar,” the EPA believes it is 

authorized by this language to follow the timing provisions of 

CAA section 110(c) as currently enacted. Second, as a general 

matter, the timing requirements of current 60.27(c) and (d), 

which effectively require the EPA to propose and finalize a 

federal plan within six6 months of the deadline for state 

submittals, may be outdated and unrealistic with respect to the 

timelines for review of state plans and the time periods for 

action, particularly as informed by the agency's experience with 

CAA section 110 SIPs (which led to the extension of the 

timelines and other changes to CAA section 110 in the 1990 

Amendments discussed above). Third, in the CPP Emission 

Guideline, the EPA has finalized a timing requirement that gives 

the agency a year to approve or disapprove a state plan or 

revision. The existing requirement in 60.27(d) that the EPA must 

promulgate a federal plan within six6 months of the initial 

deadline for state plans is therefore inconsistent with this 

provision. Fourth, existing 60.27(c) tracks the prior version of 

CAA section 110(c) with respect to the issuance of a proposed 

federal plan. This relatively prescriptive language is no longer 

present in CAA section 110(c). The procedural requirements for 

rulemakings under both CAA section 110 and 111(d) are set out in 

section 307(d) of the ActCAA, and the EPA believes those 
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provisions are appropriate and adequate to guide its rulemaking 

process for CAA section 111(d) federal plans.

The EPA invites comment on all of these proposed changes to 

the framework regulations. The EPA notes that the addition of 

these mechanisms to the framework regulations will make them 

available for all CAA section 111(d) regulations, not just those 

under the Clean Power Plan at Subpart UUUU. 

F. Proposed Interpretation regarding Existing Sources that Modify 

or Reconstruct

In the proposed rulemaking for the CPP, the EPA proposed 

the interpretation that if an existing source is subject to a 

CAA section 111(d) state plan, and then undertakes a 

modification or reconstruction, the source remains subject to 

the state plan, while also becoming subject to the modification 

or reconstruction requirements. 79 FR 34830, 34903–4. The EPA 

did not finalize a position on this issue in the final EGs rule, 

but indicated that it would re-propose and take comment on this 

issue through this federal plan rulemaking. The EPA also stated 

deferral of action on this issue does not impact states’ and 

affected EGUs’ pending obligations under this final rule 

relating to plan submission deadlines, as this issue concerns

potential obligations or impacts after an existing source has 

already become subject to the requirements of a state plan. The 
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EPA intends to finalize its position on this issue through this 

rulemaking, which will be well in advance of the plan 

performance period beginning in 2022, at which point state plan 

obligations on existing sources are effectuated. 

We noted in the Clean Power Plan proposal that CAA section 

111(d) is arguably silent as to this issue. Thus, we took this 

to grant the agency the authority to provide a reasonable 

interpretation to fill in the gaps where the statute is silent.

In the proposal for the CPP, we proposed to disallow existing 

sources to leave the CAA section 111(d) program through 

modification or reconstruction. We did this for two reasons. 

First, if a source did so, that could prove disruptive to the 

state plan. Second, allowing sources to do so could provide them 

an incentive to do so that would be contrary to the purposes of 

CAA section 111(d). We then asked for comment on “whether this 

interpretation is supported by the statutory text and whether 

this interpretation is sensible policy and will further the 

goals of the statute.”

We received many comments disagreeing with this approach. 

After reviewing these comments, the agency believes an

alternative interpretation is more appropriate in the particular 

context here. In order to give the public an opportunity to 

comment on this, we are proposing this interpretation here. That 
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is, when CAA section 111(d) emission guidelinesEGs are initially 

promulgated for existing stationary sources in response to 

corresponding CAA section 111(b) standards of performance for 

the same pollutant, the statute prevents new, modified or 

reconstructed sources (including under those particular CAA 

section 111(b) standards of performance and as those terms are 

applied in the relevant new source performance standards 

(NSPS))) from simultaneously being subject to state plans under 

those particular CAA section 111(d) emission 

guidelines.EGs. This interpretation gives meaning to the 

definition of “existing source” in CAA section 111(a)(6) and is 

consistent with the definition of “new source” in section 

111(a)(2). Further, it is consistent with the historical 

treatment of modified and reconstructed sources in the CAA 

section 111 program. 

The EPA notes the concerns it noted in the proposal 

supporting why the originally proposed interpretation was 

reasonable are being addressed in other ways in the final EGs, 

and in the proposed federal plan. In other words, there will be 

other ways to minimize disruption to state plans if such a 

modification or reconstruction were to take place. We invite 

comment on the agency’s proposed interpretation that when an 

existing source modifies or reconstructs in such a way that it 
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meets the definition of a new source, for purposes of a 

particular NSPS and emission guideline, it becomes a new source 

under the statute and is no longer subject to the CAA section 

111(d) program

G. Separate Finalization of these Changes

The agency intends to finalize these procedural changes and 

interpretation sooner than it finalizes the rest of this 

proposed action. The EPA believes these changes generally 

enhance and improve the framework regulations in a way that will 

be of benefit to the states, the EPA, and other stakeholders, 

and will improve the overall efficacy of the program. We believe 

it is important to finalize these changes to the framework 

regulations relatively quickly in order to provide states and 

other stakeholders predictability in how the EPA intends to 

process state plans and submissions under CAA section 111(d). If 

the EPA does finalize these changes sooner than the model 

trading rules or the federal plan, it will do so after the close 

of the comment period, and after consideration and response to 

any comments on these changes.

VIII. Impacts of this Action

A. Endangered Species Act 

Consistent with the requirements of section 7(a)(2) of the 
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Endangered Species Act (ESA), the EPA has considered the effects 

of this proposed rule and has reviewed applicable ESA 

regulations, case law, and guidance to determine what, if any, 

impact there may be to listed endangered or threatened species 

or designated critical habitat. Section 7(a)(2) of the ESA 

requires federal agencies, in consultation with the U.S. Fish 

and Wildlife Service (FWS) and/or the National Marine Fisheries 

Service, to ensure that actions they authorize, fund, or carry 

out are not likely to jeopardize the continued existence of 

federally listed endangered or threatened species or result in 

the destruction or adverse modification of designated critical 

habitat of such species. 16 U.S.C. 1536(a)(2). Under relevant 

implementing regulations, ESA section 7(a)(2) applies only to 

actions where there is discretionary federal involvement or 

control. 50 CFR 402.03. Further, under the regulations 

consultation is required only for actions that “may affect” 

listed species or designated critical habitat. 50 CFR § 402.14. 

Consultation is not required where the action has no effect on 

such species or habitat. Under this standard, it is the federal 

agency taking the action that evaluates the action and 

determines whether consultation is required. See 51 FR 19926, 

19949 (June 3, 1986). Effects of an action include both the 

direct and indirect effects that will be added to the 
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environmental baseline. 50 CFR 402.02. Direct effects are the 

direct or immediate effects of an action on a listed species or 

its habitat.130 Indirect effects are those that are caused by the 

action, later in time, and are reasonably certain to occur. Id.

To trigger a consultation requirement, there must thus be a 

causal connection between the federal action, the effect in 

question, and if the effect is indirect, it must be reasonably 

certain to occur.

The EPA has considered the effects of this proposed rule 

and has reviewed applicable ESA regulations, case law, and 

guidance to determine what, if any, impact there may be to 

listed species or designated critical habitat for purposes of 

ESA section 7(a)(2) consultation. The EPA notes that the 

projected environmental effects of this proposal are, like the 

EGs that it implements, positive: reductions in overall GHG 

emissions, and reductions in PM and ozone-precursor emissions 

(SOX and NOX), for EGUS that will be covered by the federal plan. 

However, the EPA’s assessment that the rule will have an overall 

 

130 See Endangered Species Consultation Handbook, U.S. Fish & 

Wildlife Service and National Marine Fisheries Service at 4-

25(March 1998) (providing examples of direct effects: e.g., 

driving an off road vehicle through the nesting habitat of a listed 

species of bird and destroying a ground nest; building a housing 

unit and destroying the habitat of a listed species).
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net positive environmental effect by virtue of reducing 

emissions of certain air pollutants does not address whether the 

rule may affect any listed species or designated critical 

habitat for ESA section 7(a)(2) purposes and does not constitute 

any finding of effects for that purpose. The fact that the rule 

will have overall positive effects on the national and global 

environment does not mean that the rule may affect any listed 

species in its habitat or the designated critical habitat of 

such species within the meaning of ESA section 7(a)(2) or the 

implementing regulations or require ESA consultation. The EPA 

has considered various types of potential effects in considering 

whether ESA consultation is required for this rule.

With respect to the projected GHG emission reductions, the 

EPA does not believe that such reductions trigger ESA 

consultation requirements under ESA section 7(a)(2). In reaching 

this conclusion, the EPA is mindful of significant legal and 

technical analysis undertaken by FWS and the U.S. Department of 

the Interior in the context of listing the polar bear as a 

threatened species under the ESA. In that context, in 2008, FWS 

and DOI expressed the view that the best scientific data 

available were insufficient to draw a causal connection between 
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GHG emissions and effects on the species in its habitat.131 The 

DOI Solicitor concluded that where the effect at issue is 

climate change, proposed actions involving GHG emissions cannot 

pass the “may affect” test of the ESA section 7 regulations and,

thus, are not subject to ESA consultation. 

The EPA has also previously considered issues relating to GHG 

emissions in connection with the requirements of ESA section 

7(a)(2). In the final EGs, the agency noted that, although the GHG 

emission reductions projected for the Emissions GuidelinesEGs are 

large (estimated reductions of about 415 million short tons of CO2

in 2030 relative to the base case), the EPA evaluated larger 

reductions in assessing this same issue in the context of the light 

duty vehicle GHG emission standards for model years 2012-2016 and 

2017-2025. There the agency projected emission reductions over the 

lifetimes of the model years in question,132 which are roughly five 

to six times those projected above and, based on air quality 

modeling of potential environmental effects, concluded that “EPA 

 

131 See, e.g., 73 FR 28212, 28300 (May 15, 2008); Memorandum from 

David Longly Bernhardt, Solicitor, U.S. Department of the Interior 

re: “Guidance on the Applicability of the Endangered Species Act’s 

Consultation Requirements to Proposed Actions Involving the 

Emission of Greenhouse Gases” (Oct. 3, 2008).

132 See 75 FR at 25438 Table I.C 2–4 (May 7, 2010); 77 FR at 62894 

Table III–68 (Oct. 15, 2012).
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knows of no modeling tool which can link these small, timeattenuated changes in global metrics to particular effects on 

listed species in particular areas. Extrapolating from global 

metric to local effect with such small numbers, and accounting for 

further links in a causative chain, remain beyond current modeling 

capabilities.” EPA, Light Duty Vehicle Greenhouse Gas Standards 

and Corporate Average Fuel Economy Standards, Response to Comment 

Document for Joint Rulemaking at 4-102 (Docket EPA-OAR-HQ-2009-

4782). The EPA reached this conclusion after evaluating issues 

relating to potential improvements from the fuel efficiency rule

relevant to both temperature and oceanographic pH outputs. The 

EPA's ultimate finding was that “any potential for a specific 

impact [of the specific federal action] on listed species in their 

habitats associated with these very small changes in average global 

temperature and ocean pH is too remote to trigger the threshold 

for ESA section 7(a)(2).” Id. The EPA believes that the same 

conclusion applies to the present rule. SeeSee also, e.g., Ground 

Zero Center for Non-Violent Action v. U.S. Dept. of Navy, 383 F. 

3d 1082, 1091-92 (9th Cir. 2004) (where). The EPA similarly 

proposes to determine that the likelihood of jeopardy to a species 

from a federalthis proposed action is extremely remote, and ESA 

does not require consultation). The EPA’s proposed conclusion is 

entirely consistent with DOI’s analysis regarding ESA requirements 
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in the context of federal actions involving GHG emissions.

With regard to non-GHG air emissions, the EPA is also 

projecting substantial reductions of SO2 and NOx as a collateral 

consequence of this proposal (which will be, as stated above, 

only a subset of the total reductions from the Emissions 

Guidelines).EGs). However, CAA section 111(d) cannot directly 

control emissions of criteria pollutants. And furthermore, a 

federal plan under CAA section 111(d)(2) does no more than 

prescribe emissions standards of the same stringency as the 

corresponding EGs. 40 CFR 60.27(e)(1). Consequently, CAA section 

111(d) provides no discretion to set a standard in a federal 

plan based on potential impacts to endangered species of reduced 

criteria pollutant emissions. ESA section 7(a)(2) consultation 

is not required with respect to the projected reductions of 

criteria pollutant emissions. See 50 CFR 402.03; see also

WildEarth Guardians v. U.S. Envt’l Protection Agency, 759 F.3d 

1196, 1207-10 (10th Cir. 2014) (the EPA has no duty to consult 

under section 7 of the ESA regarding hazardous air pollutantHAP 

controls that it did not require -- and likely lacked authority 

to require -- in a FIP for regional haze controls under section 

169A of the CAA.).

Finally, the EPA has also considered other potential effects 

of the rule (beyond reductions in air pollutants) and whether any 
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such effects are “caused by” the rule and “reasonably certain to 

occur” within the meaning of the ESA regulatory definition of the 

effects of an action. 50 CFR 402.02. The EPA recognizes, for 

instance, that questions may exist whether decisions such as 

increased utilization of solar or wind power could have effects on 

listed species. The EPA received comments on the EGs asserting 

that because potential increased reliance on wind or solar power 

may be an element of Building Block 3, and because wind and solar 

facilities may in some cases have effects on listed species, the 

EPA must consult under the ESA on this aspect of the rule. 

The EPA has carefully considered the comments and the 

correspondence from Congress as well as the case law and other 

materials cited in those documents. The EPA does not believe that 

the effects of potential future changes in the energy sector –

including increased reliance on wind or solar power as a result of 

future potential actions by states or other implementing entities

– or any potential alterations in the operations of any particular 

facility would, at the time of promulgation of a federal plan, be 

sufficiently certain to occur so as to require ESA consultation on 

the rule. The EPA appreciates that the ESA regulations call for 

consultation where actions authorized, funded, or carried out by 

federal agencies may have indirect effects on listed species or 

designated critical habitat. However, as noted above, indirect 
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effects must be caused by the action at issue and must be 

reasonably certain to occur. 

Under a federal plan, it is the EPA that would implement a 

CAA section 111(d) plan. The EPA believes that even with this 

proposed federal plan, any effects on listed species or designated 

habitat are too uncertain to require consultation under ESA section 

7. This is so for at least two reasons: (1) The EPA cannot know 

with any certainty at this stage which states will actually become 

subject to a finally promulgated federal plan. Which affected EGUs,

in which states, will be covered by this Plan can only be known 

after states have failed to submit a plan, or have had their plans 

disapproved by the EPA; and (2), the federal plan as proposed will 

be implemented through some form of emissions trading. Emissions 

trading inherently provides maximum flexibility to individual 

affected EGUs to choose their method of compliance, including 

continuing to emit the relevant pollutant at historical rates so 

long as the affected EGU holds sufficient credits or allowances. 

At this point, the EPA has no meaningful information to express in 

any more than the broadest terms how any particular affected EGU

may choose to comply with the federal plan, should it be 

promulgated for them based on their location in an area not covered 

by an approved state plan. The Services have explained that ESA

section 7(a)(2) was not intended to preclude federal actions based
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on potential future speculative effects.133 These are precisely the 

types of speculative future activities and effects currently at 

issue here. The EPA requests comment on its proposed conclusion 

that ESA section 7 consultation is not required for this action.

The EPA will continue to evaluate the scope and potential effects 

of federal planning activities for this source category to the 

extent federal plans are needed and implemented in specific areas 

and over specific sources.

B. What are the Air Impacts? 

The EPA anticipates significant emission reductions under 

the final guidelines this proposed action for the utility power 

 

133 See 51 FR at 19933 (describing effects that are “reasonably 

certain to occur” in the context of consideration of cumulative 

effects and distinguishing broader consideration that may be 

appropriate in applying a procedural statute such as the National 

Environmental Policy Act, as opposed to a substantive provision 

such as ESA section 7(a)(2) that may prohibit certain federal 

actions); Endangered Species Consultation Handbook, U.S. Fish & 

Wildlife Service and National Marine Fisheries Service at 4-

30(March 1998) (in the same context, describing indicators that an 

activity is reasonably certain to occur as including governmental 

approvals of the action or indications that such approval is 

imminent, project sponsors’ assurance that the action will 

proceed, obligation of venture capital, or initiation of 

contracts; and noting that the more governmental administrative 

discretion remains to be exercised, the less there is reasonable 

certainty the action will proceed).
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sector. Specifically, the EPA is proposing approaches in the 

finalform of mass- and rate-based trading options that provide 

flexibility in implementing emission guidelines, the EPA has 

translatedstandards for a state’s affected EGUs. Both proposed 

approaches to the federal plan would require affected EGUs to 

meet emission standards set using the source category-specific 

CO2 emission performance rates into equivalent state-level ratebased and mass-based CO2 goals in order to maximize the range of 

choices that in the Clean Power Plan EGs. 

However, at the time of this proposal, the EPA has no 

information on whether any or how many states will have in 

developing their plans.require a federal plan or will adopt a 

model rule. Because of the range of choices available to states 

and thethis lack of a priori knowledge about the specific 

choices states will make in response to the final 

goals,information, in the Regulatory Impact Analysis (RIA) for 

this final action presentsproposal, the EPA chose to examine a 

scenario where all states of the contiguous U.S. will be 

regulated under a federal plan or will adopt the model rule. 

Additionally, we examine two alternative federal plan approach 

scenarios designed to achieve these goals, which we term the “. 

The first federal plan approach assumes all states in the 

contiguous U.S. are regulated under a rate-based” illustrative
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federal plan. The second federal plan approach and the “assumes 

all contiguous states are regulated under a mass-based” 

illustrative federal plan approach.134

Under the rate-based approach, when compared to 2005, CO2

emissions are projected to be reduced by approximately 22 

percent in 2020, 28 percent in 2025, and 32 percent in 2030. 

Under the mass-based approach, when compared to 2005, CO2

emissions are projected to be reduced by approximately 23 

percent in 2020, 29 percent in 2025, and 32 percent in 2030. The 

final guidelines areproposal is projected to result in 

substantial co-benefits through reductions of SO2, NOX and PM2.5

that will have direct public health benefits by lowering ambient 

levels of these pollutants and ozone. Table [X]12 and Table [X] 

shows13 of this preamble show expected CO2 and other air 

pollutant emissions in the base case and reductions under the 

final guidelinesproposal for 2020, 2025, and 2030 for both ratebased and mass-based approaches.

Table [X].12. Summary of CO2 and Other Air Pollutant Emission 

Reductions from the Base Case under Rate-Based 

 

134 It is important to note that the differences between the 

analytical results for the rate-based and mass-based federal 

plan approaches presented may not be indicative of likely 

differences between the approaches. If one approach performs 

differently than the other on a given metric during a given time 

period, this does not imply this will apply in all instances.
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IllustrativeFederal Plan Approach

CO2

(millions

short tons)

SO2

(thousand 

short tons)

NOX

(thousand

short tons)

2020 

Base Case 2,155 1,311 1,333

Rate-based Federal Plan 

Approach

2,085 1,297 1,282

Emissions Reductions 69 14 50

2025

Base Case 2,165 1,275 1,302

Rate-based Federal Plan 

Approach

1,933 1,097 1,138

Emissions Reductions 232 178 165

2030 

Base Case 2,227 1,314 1,293

Rate-based Federal Plan 

Approach

1,812 996 1,011

Emissions Reductions 415 318 282

Source: Integrated Planning Model, 2015.

Note: Emissions may not sum due to rounding.

Table [X].13. Summary of CO2 and Other Air Pollutant Emission 

Reductions from the Base Case under Mass-Based 

IllustrativeFederal Plan Approach

CO2

(million 

short tons)

SO2

(thousand 

short tons)

NOX

(thousand 

short tons)

2020

Base Case 2,155 1,311 1,333

Mass-based Federal Plan 

Approach

2,073 1,257 1,272

Emissions Reductions 81 54 60

2025
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Base Case 2,165 1,275 1,302

Mass-based Federal Plan 

Approach

1,901 1,090 1,100

Emissions Reductions 265 185 203

2030

Base Case 2,227 1,314 1,293

Mass-based Federal Plan 

Approach

1,814 1,034 1,015

Emissions Reductions 413 280 278

Source: Integrated Planning Model, 2015.

Note: Emissions may not sum due to rounding.

The reductions in Tables [X]12 and [X]13 of this preamble

do not account for reductions in hazardous air pollutants 

(HAPs)HAP that may occur as a result of this rule. For instance, 

the fine particulate reductions presented above do not reflect 

all of the reductions in many heavy metal particulates.

C. What are the Energy Impacts? 

The final guidelinesproposed action may have important 

energy market implications. Table [X]14 of this preamble

presents a variety of important energy market impacts for 2020, 

2025, and 2030 under both the rate-based and mass-based 

illustrativefederal plan approaches described in section VIII.C

of this preamble and presented in the RIA for this proposal. 

Table [X].14. Summary Table of Important Energy Market Impacts 

for Rate-Based and Mass-Based IllustrativeFederal Plan

Approaches (Percent Change from Base Case)

Rate-Based Mass-Based
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2020 2025 2030 2020 2025 2030

Retail electricity 

prices

3% 1% 1% 3% 2% 0%

Average electricity 

bills

3% -4% -7% 2% -3% -8%

Price of coal at 

minemouth -1% -5% -4% -1% -5% -3%

Coal production for 

power sector use -5% -14% -25% -7% -17% -24%

Price of natural gas 

delivered to power 

sector

5% -8% 2% 4% -3% -2%

Natural gas use for 

electricity generation

3% -1% -1% 5% 0% -4%

These figures reflect the EPA’s illustrative modeling that 

presumes policies that lead to generation shifts and growing use 

of demand-side energy efficiencyDS-EE and renewable electricity 

generation out to 2029. If states make different 

policyimplementation choices are made than those modelled, 

impacts could be different. For instance, if states implement 

renewable and/or demand-side energy efficiency policies on a 

more aggressive time-frame, impacts on natural gas and 

electricity prices would likely be less. Implementation of other 

measures not included in the BSER calculation or compliance 

modeling, such as nuclear uprates, transmission system 
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improvements, use of energy storage technologies or retrofit 

CCS, could also mitigate gas price and/or electricity price 

impacts.

Energy market impacts from the guidelines are 

discussed more extensively in the RIA found in the docket for 

this rulemaking. 

D. What are the Compliance Costs?

The compliance costs of this finalproposed action are 

represented in this analysis as the change in electric power 

generation costs between the base case and the final rule in 

which states pursue a distinct set of strategies beyond the 

strategies taken in the base case to meet the terms of the final 

guidelines. The compliance costs estimates include cost 

estimates for demand-side energy efficiency. The compliance 

assumptions – and, therefore, the projected compliance costs -

set forth in this analysis are illustrative in nature and do not 

represent the full suite of compliance flexibilities states may 

ultimately pursue. The illustrative analysis is designed to 

reflect, to the extent possible, the scope and the nature of the 

final guidelines. However, there is considerable uncertainty 

with regards to the precise measures that states will adopt to 

meet the final requirements, because there are considerable 

flexibilities afforded to the states in developing their state 
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plans.

The incremental cost is the projected additional cost 

of complying with the guidelinesmodeled federal plan approaches 

described in section VIII.B in this preamble and presented in 

the RIA for this proposal. The incremental cost is the projected 

additional cost of complying with the proposed action in the 

year analyzed and includes the amortized cost of capital 

investment, needed new capacity, shifts between or amongst 

various fuels, deployment of demand-side energy efficiencyDS-EE

programs, and other actions associated with compliance. These 

important dynamics are discussed in more detail in the RIA in 

the rulemaking docket. 

The EPA estimates the annual incremental compliance cost for the rate-based federal plan 

approach for final emission guidelines to be $2.5 billion in 2020, $1.0 billion in 

2025 and $8.4 billion in 2030, including the costs associated with 

monitoring, reporting, and recordkeeping (MR&R).. The EPA estimates the 

annual incremental compliance cost for the mass-based federal plan approach for final 

emission guidelines to be $1.4 billion in 2020, $3.0 billion in 2025 and $5.1 billion in 

2030, including the costs associated with MR&R. 

. More detailed cost estimates are available in the RIA 

included in the rulemaking docket. 
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E. What are the Economic and Employment Impacts?

The final standards areBased on the analysis presented in 

the RIA, the proposed action is projected to result in certain 

changes to power system operation as a compliance with the 

standards. See Table [X] above14 of this preamble for a variety 

of important energy market impacts for 2020, 2025, and 2030 

under both the rate-based and mass-based illustrativefederal

plan approaches described in Section VIII.B in this preamble and 

presented in the RIA.

It is important to note that the EPA’s modeling does not 

necessarily account for all of the factors that may influence 

business decisions regarding future coal-fired capacity. Many 

power companies already factor a potential financial liability 

associated with carbon emissions into their long term capacity 

planning that would further influence business decisions to 

replace these aging assets with modern, and significantly 

cleaner, generation.

The compliance modeling done to support the final rule

assumes that overall electric demand will decrease as states 

ramp up programs that result in lower overall demand. Demandside energy efficiency levels are expected to increase such that 

they achieve about a 7.8 percent reduction on overall 

electricity demand levels in 2030 under the final guidelines.
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Changes in price or demand for electricity, natural gas, 

and coal can impact markets for goods and services produced by 

sectors that use these energy inputs in the production process 

or supply those sectors. Changes in the cost of production may 

result in changes in prices, quantities produced, and 

profitability of affected firms. The EPA recognizes that these 

guidelines provide significant flexibilities and states 

implementing the guidelines may choose to mitigate impacts to 

some markets outside the utility power sector. Similarly, demand 

for new generation or demand-side energy efficiencyDS-EE as a 

result of states implementing the guidelines can result in 

shifts in production and profitability for firms that supply 

those goods and services.

Executive Order 13563 directs federal agencies to consider 

the effect of regulations on job creation and employment. 

According to the Executive Order, “our regulatory system must 

protect public health, welfare, safety, and our environment 

while promoting economic growth, innovation, competitiveness, 

and job creation. It must be based on the best available 

science.” (Executive Order 13563, 2011) Although standard 

benefit-cost analyses have not typically included a separate 

analysis of regulation-induced employment impacts, we typically 

conduct employment analyses. During the current economic 
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recoveryWhile the economy continues to move toward full 

employment, employment impacts are of particular concern and 

questions may arise about their existence and magnitude. 

States have the responsibility and flexibility to implement 

policies and practices for compliance with the final guidelines. 

Quantifying the associated employment impacts is complicated 

by the wide range of approaches that states may use. As such, 

The EPA’s employment analysis includes projected employment 

impacts associated with illustrativemodeled federal plan 

approaches for these guidelines for the electric power industry, 

coal and natural gas production, and demand-side energy 

efficiencyDS-EE activities. These projections are derived, in 

part, from a detailed model of the utility power sector used for 

this regulatory analysis, and U.S. government data on employment 

and labor productivity. In the electricity, coal, and natural 

gas sectors, the EPA estimates that these guidelinesthe proposed

action could result in a net decrease of approximately 25,000 

job-years in 2025 for the final guidelines under the rate-based 

illustrativefederal plan approach and approximately 26,000 jobyears in 2025 under the mass-based approach. For 2030, the 

estimates of the net decrease in job-years are 31,000 under the 

rate-based approach and 34,000 under the mass-based approach. 

The agency is also offering an illustrative calculation of 
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potential employment effects due to demand-side energy 

efficiencyDS-EE programs. Employment impacts from demand-side 

energy efficiencyDS-EE programs in 2030 could range from 

approximately 52,000 to 83,000 jobs under the final 

guidelinesproposal. 

By its nature, demand-side energy efficiencyDS-EE reduces 

overall demand for electric power. The EPA recognizes as more 

efficiency is built into the U.S. power system over time, lower 

fuel requirements may lead to fewer jobs in the coal and natural 

gas extraction sectors, as well as in fossil-fuel fired EGU 

construction and operation than would otherwise have been 

expected. The EPA also recognizes the fact that, in many cases, 

employment gains and losses that might be attributable to this 

rule would be expected to affect different sets of people. 

Moreover, workers who lose jobs in these sectors may find 

employment elsewhere just as workers employed in new jobs in 

these sectors may have been previously employed elsewhere. 

Therefore, the employment estimates reported in these sectors 

may include workers previously employed elsewhere. This analysis 

also does not capture potential economy-wide impacts due to 

changes in prices (of fuel, electricity, labor, for example) or 

other factors such as improved labor productivity and reduced 

health care expenditures resulting from cleaner air. For these 
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reasons, the numbers reported here should not be interpreted as 

a net national employment impact. 

F. What are the Benefits of the Proposed Action?

Implementing the final standardsproposed action will 

generate benefits by reducing emissions of CO2 and criteria 

pollutant precursors, including SO2, NOX, and directly emitted 

particles. SO2 and NOX are precursors to PM2.5 (particles smaller 

than 2.5 microns), and NOX is a precursor to ozone. The estimated 

benefits associated with these emission reductions are beyond 

those achieved by previous EPA rulemakings including the Mercury 

and Air Toxics Standards rule. The health and welfare benefits 

from reducing air pollution are considered co-benefits for these 

standards.this proposal. For this rulemaking, we were only able 

to quantify the climate benefits from reduced emissions of CO2

and the health co-benefits associated with reduced exposure to 

PM2.5 and ozone. There are many additional benefits which we are 

not able to quantify, leading to an underestimate of monetized 

benefits. In summary, we estimate the total combined climate 

benefits and health co-benefits for the rate-based federal plan 

approach to be $3.5 to $4.6 billion in 2020, $18 to $28 billion 

in 2025, and $34 to $54 billion in 2030 (3 percent discount 

rate, 2011$). Total combined climate benefits and health cobenefits for the mass-based federal plan approach are estimated 
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to be $5.3 to $8.1 billion in 2020, $19 to $29 billion in 2025, 

and $32 to $48 billion in 2030 (3 percent discount rate, 2011$). 

A summary of the emission reductions and monetized benefits 

estimated for this rule at all discount rates is provided in 

Tables [X]15 through [X]17 of this preamble.

Table [&&&].15. Summary of the Monetized Global Climate Benefits 

for the Final GuidelinesProposal (Billions of 2011$)a

Discount Rate 

(Statistic)

Monetized Climate Benefits

YEAR 2020 2025 2030

Rate-based Federal Plan Approach

CO2 

Reductions 

(million 

short tons)

69 232 415

5 percent (average 

SC-CO2)

$0.80 $3.1 $6.4

3 percent (average 

SC-CO2)

$2.8 $10 $20

2.5 percent 

(average SC-CO2)

$4.1 $15 $29

3 percent (95th

percentile SC-CO2)

$8.2 $31 $61

Mass-based Federal Plan Approach

CO2 

Reductions 

(million 

short tons)

81 265 413
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5 percent (average 

SC-CO2)

$0.94 $3.6 $6.4

3 percent (average 

SC-CO2)

$3.3 $12 $20

2.5 percent 

(average SC-CO2)

$4.9 $17 $29

3 percent (95th

percentile SC-CO2)

$9.7 $35 $60

a Climate benefit estimates reflect impacts from CO2 emission 

changes in the analysis years presented in the table and do not 

account for changes in non-CO2 GHG emissions. These estimates are 

based on the global social cost of carbon (SC-CO2) estimates for 

the analysis years and are rounded to two significant figures. 

Table [X].16. Summary of the Monetized Health Co-Benefits in the 

U.S. for the Final GuidelinesProposal, Rate-based Federal Plan

Approach (Billions of 2011$)a

Pollutant

National 

Emission 

Reductions 

(thousands 

of short 

tons)

Monetized 

Health Cobenefits

Monetized 

Health Cobenefits

(3 percent 

discount)

(7 percent 

discount)

Rate-based Federal Plan Approach, 2020

PM2.5 precursors b

SO2 14

$0.44 to 

$0.99

$0.39 to 

$0.89

NOX 50

$0.14 to 

$0.33

$0.13 to 

$0.30

Ozone precursor c

NOX (ozone season only) 19

$0.12 to 

$0.52

$0.12 to 

$0.52
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Total Monetized Health Co-benefits $0.70 to 

$1.8

$0.64 to 

$1.7

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$3.5 to $4.6 $3.5 to $4.5

Rate-based Federal Plan Approach, 2025 

PM2.5 precursors b

SO2 178 $6.4 to $14 $5.7 to $13

NOX 165

$0.56 to 

$1.3

$0.50 to 

$1.1

Ozone precursor c

NOX (ozone season only) 70

$0.49 to 

$2.1

$0.49 to 

$2.1

Total Monetized Health Co-benefits $7.4 to $18 $6.7 to $16

Total Monetized Health Co-benefits 

combined with Monetized Climate

Benefits d

$18 to $28 $17 to $26

Rate-based Federal Plan Approach, 2030

PM2.5 precursors b

SO2 318 $12 to $28 $11 to $25

NOX 282 $1.0 to $2.3 $0.93 to 

$2.1

Ozone precursor c

NOX (ozone season 

only)

118

$0.86 to 

$3.7

$0.86 to 

$3.7

Total Monetized Health Co-benefits $14 to $34 $13 to $31

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$34 to $54 $33 to $51

a All estimates are rounded to two significant figures, so 

estimates may not sum. It is important to note that the 
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monetized co-benefits do not include reduced health effects from 

direct exposure to SO2, direct exposure to NO2, exposure to 

mercury, ecosystem effects or visibility impairment. Air 

pollution health co-benefits are estimated using regional 

benefit-per-ton estimates for the contiguous U.S.

b The monetized PM2.5 co-benefits reflect the human health 

benefits associated with reducing exposure to PM2.5 through 

reductions of PM2.5 precursors, such as SO2 and NOX. The cobenefits do not include the benefits of reductions in directly 

emitted PM2.5. These additional benefits would increase overall 

benefits by a few percent based on the analyses conducted for 

the proposed rule.Clean Power Plan EGs. PM co-benefits are shown 

as a range reflecting the use of two concentration-response 

functions, with the lower end of the range based on a function 

from Krewski et al. (2009) and the upper end based on a function

from Lepeule et al. (2012). These models assume that all fine 

particles, regardless of their chemical composition, are equally 

potent in causing premature mortality because the scientific 

evidence is not yet sufficient to allow differentiation of 

effect estimates by particle type.

c The monetized ozone co-benefits reflect the human health 

benefits associated with reducing exposure to ozone through 

reductions of NOX during the ozone season. Ozone co-benefits are 

shown as a range reflecting the use of several different 

concentration-response functions, with the lower end of the 

range based on a function from Bell, et al. (2004) and the upper 

end based on a function from Levy, et al. (2005). Ozone cobenefits occur in the analysis year, so they are the same for 

all discount rates.

d We estimate climate benefits associated with four different 

values of a one ton CO2 reduction (model average at 2.5 percent 

discount rate, 3 percent, and 5 percent; 95th percentile at 3 

percent). Referred to as the social cost of carbon, each value 

increases over time. For the purposes of this table, we show the 
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benefits associated with the model average at 3 percent discount 

rate, however we emphasize the importance and value of 

considering the full range of social cost of carbon values. We 

provide combined climate and health estimates based on 

additional discount rates in the RIA.

Table [X].17. Summary of the Monetized Health Co-Benefits in the 

U.S. for the Final GuidelinesProposal, Mass-based Federal Plan

Approach (Billions of 2011$)a

Pollutant

National 

Emission 

Reductions 

(thousands 

of short 

tons)

Monetized 

Health Cobenefits

Monetized 

Health Cobenefits

(3 percent 

discount)

(7 percent 

discount)

Mass-based Federal Plan Approach, 2020

PM2.5 precursors b

SO2 54 $1.7 to $3.8 $1.5 to $3.4

NOX 60

$0.17 to 

$0.39

$0.16 to 

$0.36

Ozone precursor c

NOX (ozone season only) 23

$0.14 to 

$0.61

$0.14 to 

$0.61

Total Monetized Health Co-benefits $2.0 to $4.8 $1.8 to $4.4

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$5.3 to $8.1 $5.1 to $7.7

Mass-based Federal Plan Approach, 2025 

PM2.5 precursors b

SO2 185 $6.0 to $13 $5.4 to $12

NOX 203

$0.58 to 

$1.3

$0.52 to 

$1.2
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Ozone precursor c

NOX (ozone season only) 88

$0.56 to 

$2.4

$0.56 to 

$2.4

Total Monetized Health Co-benefits $7.1 to $17 $6.5 to $16

Total Monetized Health Co-benefits 

combined with Monetized Climate

Benefits d

$19 to $29 $18 to $27

Mass-based Federal Plan Approach, 2030

PM2.5 precursors b

SO2 280 $10 to $23 $9.0 to $20

NOX 278

$0.87 to 

$2.0

$0.79 to 

$1.8

Ozone precursor c

NOX (ozone season 

only)

121

$0.82 to 

$3.5

$0.82 to 

$3.5

Total Monetized Health Co-benefits $12 to $28 $11 to $26

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$32 to $48 $31 to $46

a All estimates are rounded to two significant figures, so 

estimates may not sum. It is important to note that the 

monetized co-benefits do not include reduced health effects from 

direct exposure to SO2, direct exposure to NO2, exposure to 

mercury, ecosystem effects or visibility impairment. Air 

pollution health co-benefits are estimated using regional 

benefit-per-ton estimates for the contiguous U.S.

b The monetized PM2.5 co-benefits reflect the human health 

benefits associated with reducing exposure to PM2.5 through 

reductions of PM2.5 precursors, such as SO2 and NOX. The cobenefits do not include the benefits of reductions in directly 

emitted PM2.5. These additional benefits would increase overall 

benefits by a few percent based on the analyses conducted for 
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the proposed rule.Clean Power Plan EGs. PM co-benefits are shown 

as a range reflecting the use of two concentration-response 

functions, with the lower end of the range based on a function 

from Krewski et al. (2009) and the upper end based on a function

from Lepeule et al. (2012). These models assume that all fine 

particles, regardless of their chemical composition, are equally 

potent in causing premature mortality because the scientific 

evidence is not yet sufficient to allow differentiation of 

effect estimates by particle type.

c The monetized ozone co-benefits reflect the human health 

benefits associated with reducing exposure to ozone through 

reductions of NOX during the ozone season. Ozone co-benefits are 

shown as a range reflecting the use of several different 

concentration-response functions, with the lower end of the 

range based on a function from Bell, et al. (2004) and the upper 

end based on a function from Levy, et al. (2005). Ozone cobenefits occur in the analysis year, so they are the same for 

all discount rates.

d We estimate climate benefits associated with four different 

values of a one ton CO2 reduction (model average at 2.5 percent 

discount rate, 3 percent, and 5 percent; 95th percentile at 3 

percent). Referred to as the social cost of carbon, each value 

increases over time. For the purposes of this table, we show the 

benefits associated with the model average at 3 percent discount 

rate, however we emphasize the importance and value of 

considering the full range of social cost of carbon values. We 

provide combined climate and health estimates based on 

additional discount rates in the RIA.

The EPA has used the social cost of carbon (SC-CO2) 

estimates presented in the Technical Support Document: Technical 

Update of the Social Cost of Carbon for Regulatory Impact 
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Analysis Under Executive Order 12866 (May 2013, Revised JuneJuly

2015) (“current TSD”) to analyze CO2 climate impacts of this 

rulemaking.135 We refer to these estimates, which were developed 

by the U.S. government, as “SC-CO2 estimates.” The SC-CO2 is a 

metric that estimates the monetary value of impacts associated 

with marginal changes in CO2 emissions in a given year. It 

includes a wide range of anticipated climate impacts, such as 

net changes in agricultural productivity and human health, 

property damage from increased flood risk, and changes in energy 

system costs, such as reduced costs for heating and increased 

costs for air conditioning. It is typically used to assess the 

avoided damages as a result of regulatory actions (i.e., 

benefits of rulemakings that lead to an incremental reduction in 

 

135 Docket ID EPA-HQ-OAR-2013-0495, Technical Support Document: 

Technical Update of the Social Cost of Carbon for Regulatory 

Impact Analysis Under Executive Order 12866, Interagency Working 

Group on Social Cost of Carbon, with participation by Council of 

Economic Advisers, Council on Environmental Quality, Department 

of Agriculture, Department of Commerce, Department of Energy, 

Department of Transportation, Domestic Policy Council, 

Environmental Protection Agency, National Economic Council, 

Office of Management and Budget, Office of Science and 

Technology Policy, and Department of Treasury (May 2013, Revised 

July 2015). Available at: 

http://www.whitehouse.gov/sites/default/files/omb/inforeg/scctsd-final-july-2015.pdf.
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cumulative global CO2 emissions).

The SC-CO2 estimates used in this analysis were developed 

over many years, using the best science available, and with 

input from the public. Specifically, an interagency working 

group (IWG) that included the EPA and other executive branch 

agencies and offices used three integrated assessment models 

(IAMs) to develop the SC-CO2 estimates and recommended four 

global values for use in regulatory analyses. The SC-CO2

estimates were first released in February 2010 and updated in 

2013 using new versions of each IAM. The 2010 SC-CO2 Technical 

Support Document (2010 TSD)136 provides a complete discussion of 

the methods used to develop these estimates and the current TSD 

presents and discusses the 2013 update (including two recent 

 

136 Docket ID EPA-HQ-OAR-2009-0472-114577, Technical Support 

Document: Social Cost of Carbon for Regulatory Impact Analysis 

Under Executive Order 12866, Interagency Working Group on Social 

Cost of Carbon, with participation by the Council of Economic 

Advisers, Council on Environmental Quality, Department of 

Agriculture, Department of Commerce, Department of Energy, 

Department of Transportation, Environmental Protection Agency, 

National Economic Council, Office of Energy and Climate Change, 

Office of Management and Budget, Office of Science and 

Technology Policy, and Department of Treasury (February 2010). 

Also available at: 

http://www.whitehouse.gov/sites/default/files/omb/inforeg/foragencies/Social-Cost-of-Carbon-for-RIA.pdf.
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minor corrections to the estimates).137

The EPA received numerous comments on the SC-CO2 estimates 

as part of this rulemaking. The comments covered a wide range of 

topics including the technical details of the modeling conducted 

to develop the SC-CO2 estimates, the aggregation and presentation 

of the SC-CO2 estimates, and the process by which the SC-CO2

estimates were derived. Many but not all commenters were 

supportive of the SC-CO2 and its application to this rulemaking. 

Commenters also provided constructive recommendations for 

potential opportunities to improve the SC-CO2 estimates in future 

updates. Many of these comments were similar to those that OMB’s 

Office of Information and Regulatory Affairs received comments 

in response to a separate request for public comment on the 

 

137 The current version of the TSD is available at: 

https://www.whitehouse.gov/sites/default/files/omb/inforeg/sccresponse-to-comments-final-july-2015.pdf, Docket ID EPA-HQ-OAR2013-0495, Technical Support Document: Technical Update of the 

Social Cost of Carbon for Regulatory Impact Analysis Under 

Executive Order 12866, Interagency Working Group on Social Cost 

of Carbon, with participation by Council of Economic Advisers, 

Council on Environmental Quality, Department of Agriculture, 

Department of Commerce, Department of Energy, Department of 

Transportation, Domestic Policy Council, Environmental 

Protection Agency, National Economic Council, Office of 

Management and Budget, Office of Science and Technology Policy, 

and Department of Treasury (May 2013, Revised July 2015).
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approach used to develop the estimates. After careful evaluation 

of the full range of comments submitted to OMB, the IWG 

continues to recommend the use of the SC-CO2 estimates in 

regulatory impact analysisRIA.138 With the release of the 

response to comments, the IWG announced plans to obtain expert 

independent advice from the National Academies of Sciences, 

Engineering, and Medicine (Academies) to ensure that the SC-CO2

estimates continue to reflect the best available scientific and 

economic information on climate change. The Academies review 

will be informed by the public comments received and focus on 

the technical merits and challenges of potential approaches to 

improving the SC-CO2 estimates in future updates. See the EPA 

Response to Comments document for the complete response to 

comments received on SC-CO2 as part of this rulemaking. 

Concurrent with OMB’s publication of the response to 

comments on SC-CO2 and announcement of the Academies process, OMB 

posted a revised TSD that includes two minor technical 

corrections to the current estimates. One technical correction 

addressed an inadvertent omission of climate change damages in 

the last year of analysis (2300) in one model and the second 

 

138 See https://www.whitehouse.gov/omb/oira/social-cost-of-carbon

for additional details, including the OMB Response to Comments 

and the SC-CO2 TSDs. 
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addressed a minor indexing error in another model. On average 

the revised SC-CO2 estimates are one dollar less than the mean 

SC-CO2 estimates reported in the November 2013 revision to the 

May 2013 TSD. The change in the estimates associated with the 

95th percentile estimates when using a 3 percent discount rate 

is slightly larger, as those estimates are heavily influenced by 

the results from the model that was affected by the indexing 

error.

The EPA, as a member of the IWG on the SC-CO2, has carefully 

examined and evaluated the minor technical corrections in the 

revised TSD and the public comments submitted to OMB’s separate 

SC-CO2 comment process. Additionally, the EPA has carefully 

examined and evaluated all comments received regarding the SCCO2 through this rulemaking process.SC-CO2 comment process. The 

EPA concurs with the IWG’s conclusion that it is reasonable, and 

scientifically appropriate, to use the current SC-CO2 estimates 

for purposes of regulatory impact analysisRIA, including for 

this proceeding.

The four SC-CO2 estimates are as follows: $12, $40, $60, and 

$120 per short ton of CO2 emissions in the year 2020 (2011$).139

 

139 The current version of the TSD is available at: 

https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-
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The first three values are based on the average SC-CO2 from the 

three IAMs, at discount rates of 5, 3, and 2.5 percent, 

respectively. The SC-CO2 value at several discount rates are 

included because the literature shows that the SC-CO2 is quite 

sensitive to assumptions about the discount rate, and because no 

consensus exists on the appropriate rate to use in an 

intergenerational context (where costs and benefits are incurred 

by different generations). The fourth value is the 95th

percentile of the SC-CO2 from all three models at a 3 percent 

discount rate. It is included to represent higher-than-expected 

impacts from temperature change further out in the tails of the 

SC-CO2 distribution (representing less likely, but potentially 

catastrophic, outcomes).

There are limitations in the estimates of the benefits from 

the final emission guidelinesthis proposal, including the 

omission of climate and other CO2 related benefits that could not 

be monetized. The 2010 TSD discusses a number of limitations to 

the SC-CO2 analysis, including the incomplete way in which the 

IAMs capture catastrophic and non-catastrophic impacts, their 

 

tsd-final-july-2015.pdf. The 2010 and 2013 TSDs present SC-CO2 in 

2007$ per metric ton. The estimates were adjusted to (1) Short 

tons for using conversion factor 0.90718474 and (2) 2011$ using 

GDP Implicit Price Deflator, http://www.gpo.gov/fdsys/pkg/ECONI2013-02/pdf/ECONI-2013-02-Pg3.pdf.
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incomplete treatment of adaptation and technological change, 

uncertainty in the extrapolation of damages to high 

temperatures, and assumptions regarding risk aversion. 

Currently, IAMs do not assign value to all of the important 

impacts of CO2 recognized in the literature, such as ocean 

acidification or potential tipping points, for various reasons, 

including the inherent difficulties in valuing non-market 

impacts and the fact that the science incorporated into these 

models understandably lags behind the most recent research. 

Nonetheless, these estimates and the discussion of their 

limitations represent the best available information about the 

social benefits of CO2 emission reductions to inform the benefitcost analysis. As previously noted, the IWG plans to seek 

independent expert advice on technical opportunities to improve 

the SC-CO2 estimates from the Academies. The Academies process 

will help to ensure that the SC-CO2 estimates used by the federal 

government continue to reflect the best available science and 

methodologies. Additional details are provided in the TSDs.

The health co-benefits estimates represent the total 

monetized human health benefits for populations exposed to 

reduced PM2.5 and ozone resulting from emission reductions from 

the illustrative compliance strategy for the final

standards.federal plan approaches examined in the RIA for this 
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proposal. Unlike the global SC-CO2 estimates, the air pollution 

health co-benefits are estimated for the contiguous U.S. only. 

We used a “benefit-per-ton” approach to estimate the benefits of 

this rulemaking. To create the PM2.5 benefit-per-ton estimates, we 

conducted air quality modeling for an illustrative scenario 

reflecting the proposed standardsClean Power Plan EGs to convert 

precursor emissions into changes in ambient PM2.5 and ozone 

concentrations. We then used these air quality modeling results 

in BenMAP140 to calculate average regional benefit-per-ton 

estimates using the health impact assumptions used in the PM 

NAAQS RIA141 and Ozone NAAQS RIAs.142,143 The three regions were the 

 

140 http://www.epa.gov/airquality/benmap/index.html

141 U.S. Environmental Protection Agency (U.S. EPA). 2012. 

Regulatory Impact Analysis for the Final Revisions to the 

National Ambient Air Quality Standards for Particulate Matter. 

Research Triangle Park, NC: Office of Air Quality Planning and 

Standards, Health and Environmental Impacts Division. (EPA 

document number EPA-452/R-12-003, December). Available at: 

http://www.epa.gov/pm/2012/finalria.pdf.

142 U.S. Environmental Protection Agency (U.S. EPA). 2008b. Final 

Ozone NAAQS Regulatory Impact Analysis. Research Triangle Park, 

NC: Office of Air Quality Planning and Standards, Health and 

Environmental Impacts Division, Air Benefit and Cost Group 

Research. (EPA document number EPA-452/R-08-003, March). 

Available at: 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=194645>.

143 U.S. Environmental Protection Agency (U.S. EPA). 2010. Section 
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Eastern U.S., Western U.S., and California. To calculate the cobenefits for the final standardsthis proposal, we multiplied the 

regional benefit-per-ton estimates generated from modeling of 

the proposed Clean Power Plan EGs standards by the corresponding 

regional emission reductions for the final standardsthis 

proposal.144 All benefit-per-ton estimates reflect the geographic 

distribution of the modeled emissions for the proposed 

standardsClean Power Plan EGs, which may not exactly match the 

emission reductions in this finalproposed rulemaking, and thus 

they may not reflect the local variability in population 

density, meteorology, exposure, baseline health incidence rates, 

or other local factors for any specific location. More 

information regarding the derivation of the benefit-per-ton 

estimates is available in the Clean Power Plan Final Rule RIA. 

 

3: Re-analysis of the Benefits of Attaining Alternative Ozone 

Standards to Incorporate Current Methods. Available at: 

http://www.epa.gov/ttnecas1/regdata/RIAs/s3-

supplemental_analysis-updated_benefits11-5.09.pdf. 

144 U.S. Environmental Protection Agency. 2013. Technical support 

document: Estimating the benefit per ton of reducing PM2.5

precursors from 17 sectors. Research Triangle Park, NC: Office 

of Air and Radiation, Office of Air Quality Planning and 

Standards, January. Available at: 

http://www.epa.gov/airquality/benmap/models/Source_Apportionment

_BPT_TSD_1_31_13.pdf.
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PM benefit-per-ton values are generated using two 

concentration-response functions, Krewski et al. (2009)145 and 

Lepeule et al. (2012)146. These models assume that all fine 

particles, regardless of their chemical composition, are equally 

potent in causing premature mortality because the scientific 

evidence is not yet sufficient to allow differentiation of 

effect estimates by particle type. Even though we assume that 

all fine particles have equivalent health effects, the benefitper-ton estimates vary between PM2.5 precursors depending on the 

location and magnitude of their impact on PM2.5 concentrations, 

which drive population exposure. 

It is important to note that the magnitude of the PM2.5 and 

ozone co-benefits is largely driven by the concentration 

response functions for premature mortality and the value of a 

statistical life used to value reductions in premature 

mortality. For PM2.5, we use two key empirical studies, one based 

on the American Cancer Society cohort study (Krewski et al, 

 

145 Krewski D.; M. Jerrett; R. T. Burnett; R. Ma; E. Hughes; Y. 

Shi, et al. 2009. Extended Follow-up and Spatial Analysis of the 

American Cancer Society Study Linking Particulate Air Pollution 

and Mortality. Health Effects Institute. (HEI Research Report 

number 140). Boston, MA: Health Effects Institute.

146 Lepeule, J.; F. Laden; D. Dockery; J. Schwartz. 2012. 

“Chronic Exposure to Fine Particles and Mortality: An Extended 

Follow-Up of the Harvard Six Cities Study from 1974 to 2009.” 

Environmental Health Perspective, 120(7), July, pp. 965-970.
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2009) and one based on the extended Six Cities cohort study

(Lepuele et al, 2012). We present the PM2.5 co-benefits results as 

a range based on benefit-per-ton estimates calculated using the 

concentration-response functions from these two epidemiology 

studies, but this range does not capture the full range of 

uncertainty inherent in the co-benefits estimates. In the RIA 

for this rule, which is available in the docket, we also include 

PM2.5 co-benefits estimates using benefit-per-ton estimates based 

on expert judgments of the effect of PM2.5 on premature mortality

(Roman et al., 2008)147 as a characterization of uncertainty 

regarding the PM2.5-mortality relationship.

For the ozone co-benefits, we present the results as a range 

reflecting benefit-per-ton estimates which use several different 

concentration-response functions for mortality, with the lower 

end of the range based on a benefit-per-ton estimate using the

function from Bell et al. (2004)148 and the upper end based on a

benefit-per-ton estimate using the function from Levy et al. 

 

147 Roman, H., et al. 2008. “Expert Judgment Assessment of the 

Mortality Impact of Changes in Ambient Fine Particulate Matter 

in the U.S.” Environmental Science & Technology, Vol. 42, No. 7, 

February, pp. 2268 – 2274.

148 Bell, M.L., et al. 2004. “Ozone and Short-Term Mortality in 

95 U.S. Urban Communities, 1987-2000.” Journal of the American 

Medical Association, 292(19), pp. 2372-8.
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(2005).149 Similar to PM2.5, the range of ozone co-benefits does 

not capture the full range of inherent uncertainty. 

In this analysis, in estimating the benefits-per-ton for 

PM2.5 precursors, the EPA assumes that the health impact function 

for fine particles is without a threshold. This is based on the 

conclusions of the EPA’s Integrated Science Assessment for 

Particulate Matter,150 which evaluated the substantial body of 

published scientific literature, reflecting thousands of 

epidemiology, toxicology, and clinical studies that documents 

the association between elevated PM2.5 concentrations and adverse 

health effects, including increased premature mortality. This 

assessment, which was twice reviewed by the EPA’s independent 

Science Advisory Board, concluded that the scientific literature 

consistently finds that a no-threshold model most adequately 

portrays the PM-mortality concentration-response relationship. 

 

149 Levy, J.I., S.M. Chemerynski, and J.A. Sarnat. 2005. “Ozone 

exposure and mortality: an empiric Bayes metaregression 

analysis.” Epidemiology. 16(4): p. 458-68.

150 U.S. Environmental Protection Agency. 2009. Integrated 

Science Assessment for Particulate Matter (Final Report). 

Research Triangle Park, NC: National Center for Environmental 

Assessment, RTP Division. (EPA document number EPA-600-R-08-

139F, December). Available at: 

http://cfpub.epa.gov/si/si_public_record_Report.cfm?dirEntryId=2

16546.
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In general, we are more confident in the magnitude 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. 

For this analysis, policy-specific air quality data are not 

available,151 and thus, we are unable to estimate the percentage 

of premature mortality associated with this specific rule that 

is above the lowest measured PM2.5 levels (LML) for the two PM2.5

mortality epidemiology studies that form the basis for our 

analysis. As a surrogate measure of mortality impacts above the 

LML, we provide the percentage of the population exposed above 

the lowest measured PM2.5 level (LML) in each of the two studies, 

using the estimates of baseline projected PM2.5 from the air 

quality modeling for the proposed guidelines used to calculate 

the benefit-per-ton estimates for the EGU sector. Using the 

Krewski et al. (2009) study, 88 percent of the population is 

exposed to annual mean PM2.5 levels at or above the LML of 5.8 

micrograms per cubic meter (μg/m3). Using the Lepeule et al. 

 

151 In addition, site-specific emission reductions will depend 

upon how states implement the guidelines.
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(2012) study, 46 percent of the population is exposed above the 

LML of 8 μg/m3. It is important to note that baseline exposure is 

only one parameter in the health impact function, along with 

baseline incidence rates, population, and change in air quality. 

Every benefit analysis examining the potential effects of a 

change in environmental protection requirements is limited, to 

some extent, by data gaps, model capabilities (such as 

geographic coverage) and uncertainties in the underlying 

scientific and economic studies used to configure the benefit 

and cost models. Despite these uncertainties, we believe the air 

quality co-benefit analysis for this rule provides a reasonable 

indication of the expected health benefits of the air pollution 

emission reductions for the illustrative analysis of the final

standardsthis proposed action under a set of reasonable 

assumptions. This analysis does not include the type of detailed 

uncertainty assessment found in the 2012 PM2.5 National Ambient 

Air Quality Standard (NAAQS)NAAQS RIA (U.S. EPA, 2012) because 

we lack the necessary air quality input and monitoring data to 

conduct a complete benefits assessment. In addition, using a 

benefit-per-ton approach adds another important source of 

uncertainty to the benefits estimates. The 2012 PM2.5 NAAQS 

benefits analysis provides an indication of the sensitivity of 

our results to various assumptions. 
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We note that the monetized co-benefits estimates shown here 

do not include several important benefit categories, including 

exposure to SO2, NOX, and hazardous air pollutantsHAP (e.g., 

mercury and hydrogen chloride), as well as ecosystem effects and 

visibility impairment. Although we do not have sufficient 

information or modeling available to provide monetized estimates 

for this rule, we include a qualitative assessment of these 

unquantified benefits in the RIA for the final guidelines.this 

proposal. In addition, in the RIA for the final standardsthis 

proposal, we did not estimate changes in emissions of directly 

emitted particles. As a result, quantified PM2.5 related benefits 

are underestimated by a relatively small amount. In the RIA for 

the proposed guidelinesClean Power Plan EGs, the benefits from 

reductions in directly emitted PM2.5 were less than 10 percent of 

total monetized health co-benefits across all scenarios and 

years.

For more information on the benefits analysis, please refer 

to the RIA for this rule, which is available in the rulemaking 

docket.

IX. Community and Environmental Justice Considerations

In this section we provide an overview of the actions that 

the agency is taking to help ensure that vulnerable communities 
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are not disproportionately impacted by this rulemaking. 

As described in the Executive Summary, climate change is an 

environmental justiceEJ issue. Low-income communities and 

communities of color already overburdened with pollution are 

likely to be disproportionately affected by, and less resilient 

to, the impacts of climate change. This rulemaking will provide 

broad benefit to communities across the nation, as its purpose 

is to reduce greenhouse gasesGHGs, the most significant driver 

of climate change. While addressing climate change will provide 

broad benefits, it is particularly beneficial to low-income 

populations and some communities of color (in particular, 

populations defined jointly by ethnic/racial characteristics and 

geographic location) where people are most vulnerable to the 

impacts of climate change (a more robust discussion of the 

impacts of climate change on vulnerable communities is provided 

in the Executive Order 12898 section XIIX.J of this preamble). 

While climate change is a global phenomenon, the adverse effects 

of climate change can be very localized, as impacts such as 

storms, flooding, droughts, and the like are experienced in 

individual communities. 

Vulnerable communities also often receive more than their 

fair share of conventional air pollution, with the attendant 

adverse health impacts.
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The changes in electricity generation that will result from

this rule will further benefit communities by reducing existing 

air pollution that directly contributes to adverse localized 

health effects. These air quality improvements will be achieved 

through this rule because the electric generating unitsEGUs that 

emit the most greenhouse gasesGHGs also have the highest 

emissions of conventional pollutants, such as SO2, NOx, fine 

particles, and HAP. These pollutants are known to contribute to 

adverse health outcomes, including the development of heart or 

lung diseases, such as asthma and bronchitis, increased 

susceptibility to respiratory and cardiac symptoms, greater 

numbers of emergency room visits and hospital admissions, and 

premature deaths.152 The EPA expects that the reductions in 

utilization of higher-emitting units likely to occur during the 

implementation of federal plans will produce significant 

reductions in emissions of conventional pollutants, particularly 

in those communities already overburdened by pollution, which 

are often low-income communities, communities of color, and 

indigenous communities. These reductions will have beneficial 

effects on air quality and public health both locally and 

regionally. Further, this rulemaking complements other actions 

 

152 Six Common Air Pollutants. 

http://www.epa.gov/oaqps001/urbanair/
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already taken by the EPA to reduce conventional pollutant 

emissions and improve health outcomes for overburdened 

communities. 

By reducing millions of tons of CO2 emissions that are 

contributing to global greenhouse gasGHG levels and providing 

strong leadership to encourage meaningful reductions by 

countries across the globe, this rule is a significant step to 

address health and economic impacts of climate change that will 

fall disproportionately on vulnerable communities. By reducing 

millions of tons of conventional air pollutants, this proposed 

rule will lead to better air quality and improved health in 

those communities. In the comment period for the CPP, we heard 

from many commenters who recognize and welcome those benefits.

There are other ways in which the actions that result from 

this rulemaking may affect overburdened communities in positive 

or potentially adverse ways and we also heard about these from 

commenters.

While the agency expects overall emission decreases as a 

result of this rulemaking, we recognize that some EGUs may 

operate more frequently. To the extent that we project increases 

in utilization as a result of this rulemaking, we expect these 

increases to occur generally in lower-emitting NGCC units, which 

have minimal or no emissions of SO2 and HAP, lower emissions of 
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particulate matter, and much lower emissions of NOx compared to 

higher-emitting steam units. We acknowledge the concerns that 

have been raised on this point, but also the difficulty in 

anticipating prior to plan implementation where those impacts 

might occur. As described below, the EPA intends to conduct an 

assessment of whether and where emission increases may result 

from plan implementation and mitigate adverse impacts, if any, 

in overburdened communities.

In addition to the many positive anticipated health 

benefits of this rulemaking, it also will increase the use of 

clean energy and will encourage energy efficiency.EE. These 

changes in the electricity generation system, which are already 

occurring, but may be accelerated by this program, are expected 

to have other positive benefits for communities. The electricity 

sector is, and will continue to be, investing more in RE and EE. 

The construction of renewable generation and the implementation 

of energy efficiencyEE programs such as residential 

weatherization will bring investment and employment 

opportunities to the communities where they take place. It is 

important to ensure that all communities share in these

benefits. And while we estimate that the benefits of this 

program will greatly exceed its costs (as noted in the RIA for 

this rulemaking), it is also important to ensure that to the 
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extent there are increases in electricity costs, that those do 

not fall disproportionately on those least able to afford them. 

The EPA has engaged with community groups throughout this 

rulemaking and we received many comments on the issues outlined 

above from community groups, environmental justiceEJ

organizations, faith-based organizations, public health 

organizations, and others. This input has informed this final 

rulemaking and prompted the EPA to consider other steps that the 

agency can take in the short and long term to assist states and 

stakeholders to consider environmental justiceEJ and impacts to 

communities in plan development and implementation. 

It has also prompted us to work with our federal partners 

to make sure that communities have information on federal 

resources available to assist them. We describe these resources 

below, as well as resources that the EPA will be providing to 

assist communities in accessing EE/RE and financial assistance 

programs. 

Finally, and importantly, we recognize that communities 

must be able to participate meaningfully in the development of 

this rulemaking. In this section, we discuss the steps that the 

EPA is going to be taking to assist communities in engaging with 

the agency throughout the comment period of this rulemaking. 
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A. Proximity Analysis 

The EPA is committed to ensuring that there is no 

disproportionate, adverse impact on overburdened communities as 

a result of this proposed rulemaking. To provide information 

fundamental to beginning that process, the EPA has conducted a

proximity analysis for this proposed rulemaking that summarizes 

demographic data on the communities located near power plants.153

The EPA understands that, in order to prevent disproportionately 

high and adverse human health or environmental effects on these 

communities, both the agency and communities must have 

information on the communities living near facilities, including 

demographic data, and that accessing and using census data files 

requires expertise that some community groups may lack. 

Therefore, the EPA used census data from the American Community 

Survey (ACS) 2008-2012 to conduct a proximity analysis that can 

be used by communities as they engage with the agency throughout 

the comment period of this rulemaking. The analysis and its 

results are presented in the EJ Screening Report for the Clean 

Power Plan, which is located in the docket for this rulemaking 

at EPA-HQ-OAR-2015-0199.

The proximity analysis provides detailed demographic 

 

153 The proximity analysis was conducted using the EPA’s 

environmental justice mapping and screening tool, EJSCREEN.
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information on the communities located within a 3-mile radius of 

each affected power plant in the United States.U.S. Included in 

the analysis is the breakdown by percentage of community 

characteristics such as income and minority status. The analysis 

shows a higher percentage of communities of color and low-income 

communities living near power plants than national averages. It 

is important to note that the impacts of power plant emissions 

are not limited to a 3-mile radius and the impacts of both 

potential increases and decreases in power plant emissions can 

be felt many miles away. Still, being aware of the 

characteristics of communities closest to power plants is a 

starting point in understanding how changes in the plant’s air 

emissions may affect the air quality experienced by some of 

those already experiencing environmental burdens. 

Although overall there is a higher fraction of communities 

of color and low-income populations living near power plants 

than national averages, there are differences between rural and 

urban power plants. There are many rural power plants that are 

located near small communities with high percentages of lowincome populations and lower percentages of communities of 

color. In urban areas, nearby communities tend to be both lowincome communities and communities of color. In light of this 

difference between rural and urban communities proximate to 
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power plants and in order to adequately capture both the lowincome and minority aspects central to environmental justiceEJ

considerations, we use the terms “vulnerable” or “overburdened” 

when referring to these communities. Our intent is for these

terms to be understood in an expansive sense, in order to 

capture the full scope of communities, including indigenous

communities most often located in rural areas, that are central 

to our environmental justiceEJ and community considerations.

As stated in the Executive Order 12898 discussion located 

in section XIIX.J of this preamble, the EPA believes that all 

communities will benefit from this proposed rulemaking because 

this action directly addresses the impacts of climate change by 

limiting GHG emissions through the establishment of CO2 emission 

standards for existing affected fossil fuel-fired power plants. 

The EPA also believes that the information provided in the 

proximity analysis will promote engagement between vulnerable 

communities and the agency throughout the rulemaking process. In 

addition to providing the proximity analysis in the docket of 

this rulemaking, the EPA will make it publicly available on its

Clean Power Plan (CPP) Communities Portal that will be linked to 

this rulemaking’s website ().Web site 

(http://www.epa.gov/cleanpowerplan). Furthermore, the EPA has 

also created an interactive mapping tool that illustrates where 
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power plants are located and provides information on a state 

level. This tool is available at: 

www.http://cleanpowerplanmaps.epa.gov/CleanPowerPlan/.

B. Community Engagement in This Rulemaking Process 

The EPA has heard from vulnerable communities throughout

the outreach process for the Clean Power Plan that it is 

imperative for communities to have an understanding of how 

rulemakings that target climate change work. They expressed a 

desire to know how these programs may benefit their communities 

and what the potential adverse impacts of the rules may be on 

their communities. We intend to provide communities with the 

information that they need to engage with the agency throughout 

the comment period. 

We have received feedback from communities that public 

hearings, webinars and in-person meetings are the most effective 

ways to engage with them and to provide them with the 

information that they need to understand the rulemaking process. 

Therefore, for this rulemaking, in addition to conducting public 

hearings for all members of the American public (please see the 

dates section for information on the upcoming public hearings), 

the agency will hold a national webinar for communities in the 

early stages of the comment period. The goal of this webinar 

will be to walk communities through the highlights of the 
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preamble, so they have an understanding of how the rulemaking 

may potentially affect their communities and they will have the 

contextual information they need to actively engage with the 

agency throughout the comment period. 

Additionally, because we received positive feedback on the

effectiveness of the face-to-face meetings conducted on the 

regional level, each region will be offering an outreach 

meeting(s) for communities. The goal of these meetings is to 

build a level of understanding on this rulemaking to enable 

vulnerable communities to actively engage with the agency 

throughout the comment period. Furthermore, we will follow up on 

common issues raised during the outreach meetings with national 

conference calls, specifically targeted for vulnerable

communities. 

C. Providing Communities with Access to Additional Resources

In section V.D. of this preamble, we outline that we are 

seeking comment on whether a portion of this set-aside should be 

targeted to RE projects that benefit low-income communities. 

Furthermore, the EPA is seeking comment on how an low-income

community should be defined as eligible under this set-aside. We 

also seek comment on how much of the set-aside should be 

designated as targeted at over-burdened communities. We also 

request comment on whether the methods of approval and 
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distribution of allowances to projects that benefit low-income

communities should differ, and if so, in what manner, from the 

methods that are proposed to apply to other RE projects.

As discussed below, there are also many federal programs 

that can help low-income populations access the benefits of 

renewable energy, energy efficiencyRE, EE, and the economic 

benefits of a cleaner energy economy. 

In the coming months, the EPA will continue to provide 

information and resources for low-income communities on existing 

federal, state, local, and other financial assistance programs 

to encourage EE/RE opportunities that are already available to 

communities. For example the EPA will provide a catalog of 

current or recent state and local programs that have 

successfully helped communities adopt EE/RE measures. The goal 

of these resources is to help vulnerable communities gain the 

benefits of this rulemaking. The use of these RE/EE tools can 

also help low-income households reduce their electricity 

consumption and bills. 

Additionally, as part of the resources that we will be 

providing low-income communities, the EPA will provide 

information on the Adminstration’s Partnerships for Opportunity 

and Workforce and Economic Revitalization (POWER) Initative and 

other programs that specifically target economic development 
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assistance to communities affected by changes in the coal 

industry and the utility power sector.154

D. Federal Programs and Resources Available to Communities

A. Federal Programs and Resources Available to Communities

Federal agencies have a history of bringing energy 

efficiencyEE and renewable energyRE to low-income 

communities. Earlier this summer, the Administration announced a 

new initiative to scale up access to solar energy and cut energy 

bills for all Americans, in particular low- and moderate-income 

communities, and to create a more inclusive solar workforce. As 

part of this new initiative, the U.S. Department of Energy

(DOE),, the U.S. Department of Housing and Urban Development

(HUD),, U.S. Department of Agriculture (USDA),, and the EPA 

launched a National Community Solar Partnership to unlock access 

to solar energy for the nearly 50 percent of households and 

businesses that are renters or do not have adequate roof space 

to install solar systems, with a focus on low- and moderateincome communities. The Administration also set a goal to 

install 300 megawatts (MW) of renewable energyRE in federally 

subsidized housing by 2020 and plants to provide technical 

assistance to make it easier to install solar energy on 

 

154 http://www.eda.gov/power/.
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affordable housing, including clarifying how to use federal 

funding for energy efficiencyEE and renewable energyRE. To 

continue enhancing employment opportunities in the solar 

industry for all Americans, AmeriCorps is providing funding to 

deploy solar energy and create jobs in underserved communities, 

and DOE is working to expand solar energy education and 

opportunities for job training.

These recent announcements build on the many existing federal 

programs and resources available to improve energy efficiencyEE

and accelerate the deployment of renewable energyRE in vulnerable 

communities. Some examples of these resources include: the 

Department of Energy’sDOE’s Weatherization Assistance Program, 

Health and Human Service’s Low Income Home Energy Assistance 

Program, the Department of Agriculture’s Energy Efficiency and 

Conservation Loan Program, High Cost Energy Grant Program, and the 

Rural Housing Service’s Multi-Family Housing Program.

HUDThe U.S. Department of Housing and Urban Development

supports energy efficiencyEE improvements and the deployment of 

renewable energyRE on affordable housing through its Energy 

Efficient Mortgage Program, Multifamily Property Assessed Clean 

Energy Pilot with the State of California, PowerSaver Program, 

and the use of Section 108 Community Development Block 
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Grants. The Department of Treasury provides several tax credits 

to support renewable energyRE development and energy 

efficiencyEE in low-income communities, including the New 

Markets Tax Credit Program and the Low-Income Housing Tax 

Credit. The EPA’s RE-Powering America’s Land Initiative promotes 

the reuse of potentially contaminated lands, landfills and mine 

sites – many of which are in low-income communities – for 

renewable energyRE through a combination of tailored 

redevelopment tools for communities and developers, as well as 

site-specific technical support. The EPA’s Green Power 

Partnership is increasing community use of renewable electricity 

across the country and in low-income communities. The EPA 

partners with energy efficiencyEE programs throughout the 

country that leverage ENERGY STAR to deliver broad consumer 

energy-saving benefits, of particular value to low-income 

households who can least afford high energy bills. ENERGY STAR 

also works with houses of worship to reduce energy costs –

savings that can then be repurposed to their community mission, 

including programs and assistance to residents in low-income 

communities. The EPA will be working with these federal partners 

and others to ensure that states and vulnerable communities have 

access to information on these programs and their resources.
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The federal government also has a number of programs to 

expand employment opportunities in the energy sector, including 

for underserved populations. Examples of these include HUDthe 

U.S. Department of Housing and Urban Development, DOE, and the 

Department of Education’s “STEM, Energy, and Economic 

Development” program; DOE’s Diversity in Science and Technology 

Advances National Clean Energy in Solar (DISTANCE-Solar) 

Program; Grid Engineering for Accelerated Renewable Energy 

Deployment (GEARED); the Department of Labor’s Trade Adjustment 

Assistance Community College and Career Training (TAACCCT), 

Apprenticeship USA Advancing Apprenticeships in the Energy 

Field, Job Corps Green Training and Greening of Centers, and 

YouthBuild; and the EPA’s Environmental Workforce Development 

and Job Training (EWDJT) program. 

E. Co-Pollutants

Air quality in a given area is affected by emissions from 

nearby sources and may be influenced by emissions that travel 

hundreds of miles and mix with emissions from other sources.155

In the Cross-State Air Pollution RuleCSAPR the EPA used its 

authority to reduce emissions that significantly contribute to 

downwind exposures. The RIA for the final Cross-State Air 

 

155 76 FR 48348.
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Pollution RuleCSAPR anticipates substantial health benefits for 

the population across a wide region. Similarly, the EPA believes 

that, like the Cross-State Air Pollution RuleCSAPR, this 

rulemaking will result in significant health benefits because it 

will reduce co-pollutant emissions of SO2 and NOx on a regional

and national basis.156 Thus, localized increases in NOx emissions 

may well be more than offset by NOx decreases elsewhere in the 

region that produce a net improvement in ozone and particulate 

concentrations across the area.

Another effect of the final CO2 emission standards for 

affected existing fossil fuel-fired EGUs may be increased 

utilization of other, unmodified EGUs - in particular, high 

efficiency gas-fired EGUs - with relatively low GHG emissions 

per unit of electrical output. These plants may operate more 

hours during the year and could emit pollutants, including 

pollutants whose environmental effects would be localized and

regional rather than global as is the case with GHG emissions. 

Changes in utilization already occur in response to energy 

demands and evolving energy sources, but the final CO2 emission 

standards for affected existing fossil fuel-fired EGUs can be 

expected to cause more such changes. Increased utilization of 

 

156 76 FR 48347.
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solid fossil fuel-fired units generally would not increase peak 

concentrations of PM2.5, NOx, or ozone around such EGUs to levels 

higher than those that are already occurring because peak hourly 

or daily emissions generally would not change; however, 

increased utilization may make periods of relatively high 

concentrations more frequent. It should be noted that the gasfired sources likely to be dispatched more frequently have very 

low emissions of primary PM, SO2, and HAP per unit of electrical 

output and that they must continue to comply with other CAA 

requirements that directly address the conventional pollutants, 

including federal emission standards, rules included in state 

implementation plansSIPs, and conditions in title V operating 

permits, in addition to the guidelines in this final rulemaking. 

Therefore, local (or regional) air quality for these pollutants 

is not likely to be significantly affected. For natural gasfired EGUs, the EPA found that regulation of HAP emissions “is 

not appropriate or necessary because the impacts due to HAP 

emissions from such units are negligible based on the results of 

the study documented in the utility RTC.”157 Because gas-fired 

EGUs emit essentially no mercury, increased utilization will not 

increase methyl mercury concentrations in water bodies near 

 

157 65 FR 79831.
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these affected EGUs. In studies done by DOE/NETL comparing cost 

and performance of coal-and NGCC-fired generation, they assumed 

SO2, NOx, PM (and Hg) emissions to be “negligible.” Their studies 

predict NOx emissions from a NGCC unit to be approximately 10 

times lower than a subcritical or supercritical coal-fired 

boiler.158 Many, although not all, NGCC units are also very well 

controlled for emissions of NOx through the application of after 

combustion controls such as selective catalytic reduction. 

F. Assessing Impacts of Federal Plan Implementation 

It is important to the EPA that the implementation of 

federal plans be assessed in order to identify whether they 

cause any adverse impacts on communities already overburdened by 

disproportionate environmental harms and risks. The EPA will 

conduct its own assessment during the implementation phase of 

this rulemaking to determine whether the implementation of 

federal plans and other air quality rules are, in fact, reducing 

emissions and improving air quality in all areas and, or whether 

there are localized air quality impacts that need to be 

addressed under the Clean other CAA authorities.

 

158 “Cost and Performance Baseline for Fossil Energy Plants Volume 

1: Bituminous Coal and Natural Gas to Electricity” Rev 2a, 

September 2013 Revision 2, November 2010 DOE/NETL-2010/1397.
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The EPA will provide trainings for communities on resources 

that they can use to assess localized impacts, especially 

effects of co-pollutants, of plans on their communities. This 

training will include guidance in accessing the publicly 

available information that sources and states currently report 

that can help with ongoing assessments of federal plan impacts. 

For example, unit-specific emissions data and air quality 

monitoring data are readily available. This information, 

together with the assessment that the EPA will conduct in the 

implementation phase of this rulemaking will enable the agency 

and communities to monitor any disproportionate emissions that 

may result in adverse impacts and address them. 

G. The EPA’s Continued Engagement 

The EPA is committed to helping ensure that this action 

will not have disproportionate adverse human health or 

environmental effects on vulnerable communities. Throughout the 

implementation phase of this rulemaking, the agency will 

continue to provide trainings and resources to assist 

communities and as they engage with the agency. The EPA, through 

its outreach efforts during the comment period, will continue to 

solicit feedback from communities on what they would like 

additional trainings and resources on.

As described above, the EPA will assess the impacts of this 
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rulemaking during its implementation. The EPA will house this 

assessment, along with the proximity analysis and other 

information generated throughout the implementation process, on 

its Clean Power Plan (CPP) Communities Portal that will be 

linked to this rulemaking’s website ().Web site 

(http://www.epa.gov/cleanpowerplan). In addition, the EPA has 

expanded its set of resources that are being developed to help 

communities understand the breadth of policy options and 

programs that have successfully brought EE/RE to low-income 

communities. The EPA is committed to continuing its engagement 

with communities from the comment period of this rulemaking 

through federal plan implementation.

The EPA consulted its May 2015, Guidance on Considering 

Environmental Justice During the Development of Regulatory 

Actions, when crafting this rulemaking.159 A more detailed 

discussion concerning the application of Executive Order 12898 

in this rulemaking can be found in section XIX.J of this 

preamble. A summary of the EPA’s interactions with communities 

is in the EJ Screening Report for the Clean Power Plan, 

 

159 Guidance on Considering Environmental Justice During the 

Development of Regulatory Actions. 

http://www.epa.gov/environmentaljustice/resources/policy/considering-ej-inrulemaking-guide-final.pdf. May 2015.
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available in the docket of this rulemaking. Furthermore, the 

EPA’s responses to public comments, including comments received 

from communities, are provided in the response to comments 

documents located in the docket for this rulemaking.

In summary, the EPA in this proposed rulemaking has designed 

an integrative approach that helps to ensure that vulnerable 

communities are not disproportionately impacted by this rule. The 

proximity analysis that the agency has conducted is a central 

component of this approach. Not only is the proximity analysis a 

useful tool to help identify communities that may be impacted by 

this rulemaking; it will also help communities as they engage with 

the EPA throughout the comment period. It will help the EPA as we 

help low-income communities access EE/RE and financial assistance 

programs. Finally, in order to continue to ensure that overburdened 

communities are not disproportionately impacted by this rule, the 

EPA will be conducting an assessment during the implementation 

phase of the effects of this and other rules on air quality. 

X. Statutory and Executive Order Reviews

Additional information about these statutes and Executive 

Orders can be found at .http://www2.epa.gov/lawsregulations/laws-and-executive-orders.
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A. Executive Order 12866: Regulatory Planning and Review and 

Executive Order 13563: Improving Regulation and Regulatory 

Review 

This finalproposed action is an economically significant 

regulatory action that was submitted to the OMB for review. Any 

changes made in response to OMB recommendations have been 

documented in the docket. The EPA prepared an analysis of the 

potential costs and benefits associated with this action. This 

analysis, which is contained in the “Regulatory Impact Analysis 

for Clean Powerthe Proposed Federal Plan Final RuleRequirements 

for Greenhouse Gas Emissions from Electric Utility Generating 

Units Constructed on or Before January 8, 2014; Model Trading 

Rules; Amendments to Framework Regulations” (EPA-452/R-15-

003006, July 2015), is available in the docket and is briefly 

summarized in section XIVIII of this preamble. 

Consistent with Executive Order 12866 and Executive Order 

13563, the EPA estimated the costs and benefits for illustrative 

compliancetwo alternative federal plan approaches ofto

implementing the guidelines.proposed federal plan and model 

trading rules. The final rule establishes: 1) carbon dioxide 

(CO2) emissionproposed action will achieve the same levels of 

emissions performance rates for two source categories of 

existing fossil fuel-fired EGUs, fossil fuel-fired electric 
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utility steam generating units and stationary combustion 

turbines, and 2) guidelines for the development, submittal and 

implementationas required of state plans that implementunder the 

CO2 emission performance ratesCAA section 111(d) EGs for the 

control of CO2. Actions taken to comply with the guidelines will 

also reduce the emissions of directly-emitted PM2.5, SO2 and NOX. 

The benefits associated with these PM2.5, SO2 and NOX reductions 

are referred to as co-benefits, as these reductions are not the 

primary objective of this rule.

The RIA for this proposal analyzed two implementation scenarios, which we term the 

“rate-based federal plan approach” and the “mass-based federal plan approach”. It is very 

important to note that the differences between the analytical results for the rate-based and massbased federal plan approaches presented in the RIA may not be indicative of likely differences 

between the approaches if implemented by states and affected EGUs in response to the proposed 

rule. In other words, if one approach performs differently than the other on a given metric during 

a given time period, this does not imply this will apply in all instances.

It is important to note that the potential regulatory impacts presented in the Clean Power 

Plan Final Rule RIA and the RIA for this proposed rule are not additive. Both RIAs present 

estimates of the benefits and costs of achieving the emission performance rates of the Clean 

Power Plan EGs. In the case of the Clean Power Plan Final Rule RIA, the illustrative analysis 

assumes the performance rates are met under state plans. In the case of this RIA for the proposed 

federal plan and model trading rules, the same performance rates are accomplished but are 

assumed to be achieved under the federal plan or model trading rules.
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The EPA has used the social cost of carbon estimates presented in the Technical 

Support Document: Technical Update of the Social Cost of Carbon for Regulatory 

Impact Analysis Under Executive Order 12866 (May 2013, Revised July 2015) (“current 

TSD”) to analyze CO2 climate impacts of this rulemaking. We refer to these estimates, 

which were developed by the U.S. government, as “SC-CO2 estimates.” The SC-CO2 is 

an estimate of the monetary value of impacts associated with a marginal change in CO2

emissions in a given year. The four SC-CO2 estimates are associated with different 

discount rates (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th

percentile at 3 percent), and each increases over time. In this summary, the EPA provides 

the estimate of climate benefits associated with the SC-CO2 value deemed to be central in 

the current TSD: the model average at 3 percent discount rate. 

In the final emission guidelines, the EPA has translated 

the source category-specific CO2 emission performance rates into 

equivalent state-level rate-based and mass-based CO2 goals in 

order to maximize the range of choices that states will have in 

developing their plans. Because of the range of choices 

available to states and the lack of a priori knowledge about the 

specific choices states will make in response to the final 

goals, the Regulatory Impact Analysis (RIA) for this rule 

analyzed two implementation scenarios designed to achieve these 

goals, which we term the “rate-based” illustrative plan approach 

and the “mass-based” illustrative plan approach.

It is very important to note that the differences between 
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the analytical results for the rate-based and mass-based 

illustrative plan approaches presented in the RIA may not be 

indicative of likely differences between the approaches if 

implemented by states and affected EGUs in response to the final 

guidelines. Rather, the two sets of analyses are intended to 

illustrate two different approaches to accomplish the emission 

performance rates finalized in the Clean Power Plan Final Rule. 

In other words, if one approach performs differently than the 

other on a given metric during a given time period, this does 

not imply this will apply in all instances in all time periods 

in all places.

The EPA estimates that, in 2020, the final guidelinesproposal will yield 

monetized climate benefits (in 2011$) of approximately $2.8 billion for the rate-based 

approach and $3.3 billion for the mass-based approach (3 percent model average). For the 

rate-based approach, the air pollution health co-benefits in 2020 are estimated to be $0.7 

billion to $1.8 billion (2011$) for a 3 percent discount rate and $0.64 billion to $1.7 

billion (2011$) for a 7 percent discount rate. For the mass-based approach, the air 

pollution health co-benefits in 2020 are estimated to be $2.0 billion to $4.8 billion 

(2011$) for a 3 percent discount rate and $1.8 billion to $4.4 billion (2011$) for a 7 

percent discount rate. The annual, illustrative compliance costs estimated by 

IPM and inclusive of demand-side energy efficiencyDS-EE program and 

participant costs and MRR costs in 2020, are approximately $2.5 billion for the ratebased approach and $1.4 billion for the mass-based approach (2011$). The quantified net 
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benefits (the difference between monetized benefits and compliance costs) in 2020 are 

estimated to range from $1.0 billion to $2.1 billion (2011$) for the rate-based approach 

and from $3.9 billion to 6.7 billion (2011$) for the mass-based approach, using a 3 

percent discount rate (model average).

The EPA estimates that, in 2025, the final guidelinesproposal will yield 

monetized climate benefits (in 2011$) of approximately $10 billion for the rate-based approach 

and $12 billion for the mass-based approach (3 percent model average). For the rate-based 

approach, the air pollution health co-benefits in 2025 are estimated to be $7.4 billion to $18 

billion (2011$) for a 3 percent discount rate and $6.7 billion to $16 billion (2011$) for a 7 

percent discount rate. For the mass-based approach, the air pollution health co-benefits in 2025 

are estimated to be $7.1 billion to $17 billion (2011$) for a 3 percent discount rate and $6.5 

billion to $16 billion (2011$) for a 7 percent discount rate. The annual, illustrative

compliance costs estimated by IPM and inclusive of demand side energy 

efficiencyDS-EE program and participant costs and MRR costs in 2025, are approximately 

$1.0 billion for the rate-based approach and $3.0 billion for the mass-based approach (2011$). 

The quantified net benefits (the difference between monetized benefits and compliance costs) in 

2025 are estimated to range from $17 billion to $27 billion (2011$) for the rate-based approach 

and $16 billion to $26 billion (2011$) for the mass-based approach, using a 3 percent discount 

rate (model average).

The EPA estimates that, in 2030, the final guidelinesproposal will yield 

monetized climate benefits (in 2011$) of approximately $20 billion for the rate-based approach 

and $20 billion for the mass-based approach (3 percent model average). For the rate-based 
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approach, the air pollution health co-benefits in 2030 are estimated to be $14 billion to $34 

billion (2011$) for a 3 percent discount rate and $13 billion to $31 billion (2011$) for a 7 percent 

discount rate. For the mass-based approach, the air pollution health co-benefits in 2030 are 

estimated to be $12 billion to $28 billion (2011$) for a 3 percent discount rate and $11 billion to 

$26 billion (2011$) for a 7 percent discount rate. The annual, illustrative compliance 

costs estimated by IPM and inclusive of demand side energy efficiencyDS-EE

program and participant costs and MRR costs in 2030, are approximately $8.4 billion for the 

rate-based approach and $5.1 billion for the mass-based approach (2011$). The quantified net 

benefits (the difference between monetized benefits and compliance costs) in 2030 are estimated 

to range from $26 billion to $45 billion (2011$) for the rate-based approach and from $26 billion 

to $43 billion (2011$) for the mass-based approach, using a 3 percent discount rate (model 

average).

Table [X]18 and Table [X]19 of this preamble provide the estimates of the climate 

benefits, health co-benefits, compliance costs and net benefits of the final emission 

guidelinesproposal for rate-based and mass-based illustrativefederal plan approaches, 

respectively.

Table [X].18. Summary of the Monetized Benefits, Compliance 

Costs, and Net Benefits for the Final GuidelinesProposal in 

2020, 2025 and 2030

Under the Rate-Based IllustrativeFederal Plan Approach [Billions 

of 2011$]a

Rate-Based Approach
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2020 2025 2030

Climate 

Benefitsb

5% discount 

rate $0.80 $3.1 $6.4

3% discount 

rate $2.8 $10 $20

2.5% 

discount 

rate

$4.1 $15 $29

95th 

percentile 

at 3% 

discount 

rate

$8.2 $31 $61

Air Quality Co-benefits Discount Rate

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

Air Quality 

Health Cobenefitsc

$0.70 

to $1.8

$0.64 

to $1.7

$7.4 

to $18

$6.7 to 

$16

$14 to 

$34

$13 to 

$31

Compliance 

Costsd $2.5 $1.0 $8.4

Net 

Benefitse

$1.0 to 

$2.1

$1.0 to 

$2.0

$17 to 

$27

$16 to 

$25

$26 to 

$45

$25 to 

$43

NonMonetized 

Benefits

Non-monetized climate benefits

Reductions in exposure to ambient NO2 and SO2

Reductions in mercury deposition

Ecosystem benefits associated with reductions in 

emissions of NOX, SO2, PM, and mercury

Visibility impairment

a All are rounded to two significant figures, so figures may not 
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sum.

b The climate benefit estimate in this summary table reflects 

global impacts from CO2 emission changes and does not account for 

changes in non-CO2 GHG emissions. Also, different discount rates 

are applied to SC-CO2 than to the other estimates because CO2

emissions are long-lived and subsequent damages occur over many 

years. The benefit estimates in this table are based on the 

average SC-CO2 estimated for a 3 percent discount rate. However, 

we emphasize the importance and value of considering the full 

range of SC-CO2 values. As shown in the RIA, climate benefits are 

also estimated using the other three SC-CO2 estimates (model 

average at 2.5 percent discount rate, 3 percent, and 5 percent; 

95th percentile at 3 percent). The SC-CO2 estimates are yearspecific and increase over time. 

c The air pollution health co-benefits reflect reduced exposure to PM2.5 and ozone associated with 

emission reductions of SO2 and NOX. The range reflects the use of concentration-response 

functions from different epidemiology studies. The co-benefits do not include the benefits of 

reductions in directly emitted PM2.5. These additional benefits would increase overall benefits by 

a few percent based on the analyses conducted for the Clean Power Plan proposed rule. The 

reduction in premature fatalities each year accounts for over 98 percent of total monetized cobenefits from PM2.5 and ozone. These models assume that all fine particles, regardless of their 

chemical composition, are equally potent in causing premature mortality because the scientific 

evidence is not yet sufficient to allow differentiation of effect estimates by particle type.

d Total Costs are approximated by the illustrative compliance costs estimated using the 

Integrated Planning ModelIPM for the final guidelinesthis proposal and a 

discount rate of approximately 5 percent. This estimate includes monitoring, recordkeeping, and 

reporting costs and demand-side energy efficiencyDS-EE program and participant 

costs.

e The estimates of net benefits in this summary table are 

calculated using the global SC-CO2 at a 3 percent discount rate 

(model average). The RIA includes combined climate and health 

estimates based on additional discount rates.

Table [X].19. Summary of the Monetized Benefits, Compliance 

Costs, and Net Benefits for the Final GuidelinesProposal in 

2020, 2025 and 2030
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Under the Mass-Based IllustrativeFederal Plan Approach [Billions 

of 2011$]a

Mass-Based Approach

2020 2025 2030

Climate 

Benefitsb

5% discount 

rate $0.9 $3.6 $6.4

3% discount 

rate $3.3 $12 $20

2.5% 

discount 

rate

$4.9 $17 $29

95th 

percentile 

at 3% 

discount 

rate

$9.7 $35 $60

Air Quality Co-benefits Discount Rate

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

Air Quality 

Health Cobenefitsc

$2.0 to 

$4.8

$1.8 to 

$4.4

$7.1 

to $17

$6.5 to 

$16

$12 to 

$28

$11 to 

$26

Compliance 

Costsd $1.4 $3.0 $5.1

Net 

Benefitse

$3.9 to 

$6.7

$3.7 to 

$6.3

$16 to 

$26

$15 to 

$24

$26 to 

$43

$25 to 

$40

NonMonetized 

Benefits

Non-monetized climate benefits

Reductions in exposure to ambient NO2 and SO2

Reductions in mercury deposition
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Ecosystem benefits associated with reductions in 

emissions of NOX, SO2, PM, and mercury

Visibility improvement

a All are rounded to two significant figures, so figures may not 

sum.

b The climate benefit estimate in this summary table reflects 

global impacts from CO2 emission changes and does not account for 

changes in non-CO2 GHG emissions. Also, different discount rates 

are applied to SC-CO2 than to the other estimates because CO2

emissions are long-lived and subsequent damages occur over many 

years. The benefit estimates in this table are based on the 

average SC-CO2 estimated for a 3 percent discount rate. However,

we emphasize the importance and value of considering the full 

range of SC-CO2 values. As shown in the RIA, climate benefits are 

also estimated using the other three SC-CO2 estimates (model 

average at 2.5 percent discount rate, 3 percent, and 5 percent; 

95th percentile at 3 percent). The SC-CO2 estimates are yearspecific and increase over time. 

c The air pollution health co-benefits reflect reduced exposure to PM2.5 and ozone associated with 

emission reductions of SO2 and NOX. The co-benefits do not include the benefits of reductions in 

directly emitted PM2.5. These additional benefits would increase overall benefits by a few percent 

based on the analyses conducted for the Clean Power Plan proposed rule. The range reflects the 

use of concentration-response functions from different epidemiology studies. The reduction in 

premature fatalities each year accounts for over 98 percent of total monetized co-benefits from 

PM2.5 and ozone. These models assume that all fine particles, regardless of their chemical

composition, are equally potent in causing premature mortality because the scientific evidence is 

not yet sufficient to allow differentiation of effect estimates by particle type.

d Total Costs are approximated by the illustrative compliance costs estimated using the 

Integrated Planning Model for the final guidelinesthis proposal and a discount rate of 

approximately 5 percent. This estimate includes monitoring, recordkeeping, and reporting costs 

and demand-side energy efficiencyDS-EE program and participant costs.

e The estimates of net benefits in this summary table are 

calculated using the global SC-CO2 at a 3 percent discount rate 

(model average). The RIA includes combined climate and health 

estimates based on additional discount rates.

There are additional important benefits that the EPA could not monetize. Due to current 
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data and modeling limitations, our estimates of the benefits from reducing CO2 emissions do 

not include important impacts like ocean acidification or potential tipping points in natural or 

managed ecosystems. Unquantified benefits also include climate benefits from reducing 

emissions of non-CO2 greenhouse gasesGHGs (e.g., nitrous oxide and methane) and cobenefits from reducing direct exposure to SO2, NOX, and hazardous air 

pollutantsHAP (e.g., mercury), as well as from reducing ecosystem effects and visibility 

impairment. Based upon the foregoing discussion, it remains clear that the benefits of this 

finalproposed action are substantial, and far exceed the costs. Additional details on benefits, 

costs, and net benefits estimates are provided in thisthe RIA for this proposal.

B. Paperwork Reduction Act (PRA)

[&&&based on preliminary analysis]

The information collection requirements in this rule have 

been submitted for approval to OMB under the PRA. The 

Information Collection Request (ICR) document prepared by the 

EPA has been assigned the EPA ICR number [&&&placeholder for ICR 

number].2526.01. 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 not enforceable until 

approved by OMB.

This rule does not directly impose specific requirements on 

state and U.S. territory governments with affected EGUs. The 

rule also does not impose specific requirements on tribal 
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governments that have affected EGUs located in their area of 

Indian country. This rule does impose specific requirements on 

EGUs located in states, U.S. territories or areas of Indian 

country.

The information collection activities in this proposed rule 

are consistent with those activities defined under the Carbon 

Pollution Emission Guidelines for Existing Stationary Sources: 

Electric Utility Generating Units (79&&&XX([insert FR 

34830XXX;number]; the Clean Power Plan) finalized on &&&July 

31August 3, 2015. The information collection requirements in 

this proposed rule have been submitted for approval to the 

Office of Management and Budget (OMB) under the Paperwork 

Reduction Act, 44 U.S.C. 3501 et seq. The Information Collection 

Request (ICR) document prepared by the EPA has been assigned EPA 

ICR number &&&XX2526.01. You can find a copy of the ICR in the 

docket for this rule, and it is briefly summarized here. 

Aside from reading and understanding the rule, this 

proposed action would impose minimal new information collection 

burden on affected EGUs beyond what those affected EGUs would 

already be subject to under the authorities of CAA parts 75 and 

98. OMB has previously approved the information collection 

requirements contained in the existing part 75 and 98 

regulations (40 CFR part 75 and 40 CFR part 98) under the 
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provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et 

seq. and has assigned OMB control numbers 2060–0626 and 2060–

0629, respectively. Apart from certain reporting costs based on 

requirements in the NSPS General Provisions (40 CFR part 60, 

subpart A), which are mandatory for all owners/operators subject 

to CAA section 111 national emission standards, there are no new 

information collection costs, as the information required by 

this proposed rule is already collected and reported by other 

regulatory programs. The recordkeeping and reporting 

requirements are specifically authorized by CAA section 114 (42 

U.S.C. 7414). All information submitted to the 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 B.

Although EPA cannot determine at this time how many 

affected EGU respondents will submit information under the 

federal plan, EPA has estimated an “upper bound” burden estimate 

for this ICR that estimates burden should every affected EGU 

read and understand the rule. This is the only potential 

respondent activity that would be required under the 3-year 

period following publication of the final federal plan, so there 

are no obligations to respond in this period. The results of 

this “upper bound” estimate of federal plan burden are presented 
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below:

Respondents/affected entities: 1,028

Respondents’s obligation to respond: Not applicable, no 

responses are required during the period covered by the ICR.

Estimated number of respondents: Unknown at this time, but 

have assumed all affected entities are respondents for an upper 

bound estimate. 

Frequency of response: None, no responses are required 

during the period covered by the ICR.

Total estimated burden: 17,133 hours (per year). Burden is 

defined at 5 CFR 1320.3(b).

Total estimated cost: $1,706,501 (per year)

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 the 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 the 

EPA using the docket identified at the beginning of this rule. 

You may also send your ICR-related comments to OMB’s Office of 

Information and Regulatory Affairs via email to 
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oria_submissions@omb.eop.gov, Attention: Desk Officer for the 

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 [insert date 30 days after date of publication in 

the Federal Register]. The EPA will respond to any ICR-related 

comments in the final rule.

C. Regulatory Flexibility Act (RFA)

Pursuant to section 603 of the RFA, the EPA prepared an 

initial regulatory flexibility analysis (IRFA) that examines the 

impact of the proposed rule on small entities along with 

regulatory alternatives that could minimize that impact. The

complete IRFA is available for review inwithin the RIA in docket

EPA-HQ-OAR-2015-0199 and is summarized here. 

[&&&Insert summary of IRFA here]

The small entities subject to the requirements of this 

proposed rule may include privately-owned and publicly-owned 

entities, and rural electric cooperatives that are majority 

owners of affected EGUs. EPA conducted this regulatory 

flexibility analysis at the highest level of ownership, 

evaluating parent entities with the largest share of ownership 

in at least one potentially-affected EGU included in EPA’s Base 

Case using the Integrated Planning Model (IPM) v.5.15, used in 

the RIA for this proposed rule. This analysis drew on parsed 
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unit-level estimates using IPM results for 2030.

EPA identified 223 potentially affected EGUs owned by 74 

small entities included in 2030 projections from EPA’s IPM 

v.5.15. Fifty-nine of these potentially affected EGUs are 

projected to no longer be operating by 2030 in the Base Case of 

EPA’s version of IPM. Twenty-four small entities are projected 

to have all of their potentially affected EGUs cease operation 

by 2030 in this base case.

EPA estimated net compliance costs for individual EGUs for 

the proposed rule using components for operating and annualized 

capital costs, fuel costs, demand-side energy efficiency program 

costs, and revenue changes. This approach is consistent with 

previous proposed power sector regulations, but also adds the 

additional component of change in demand-side energy efficiency 

program costs. Investment in demand-side energy efficiency 

results in lower electricity demand, and consequently fewer 

emissions as production is reduced to meet the lower demand, an 

important emission-reduction strategy modelled in the rate-based 

and mass-based federal plan approaches. For this analysis, EPA 

used the parsed unit-level estimates to estimate three of the 

four components of the net compliance cost equation using IPM 

outputs: the change in operating and annualized capital costs, 

the change in fuel costs, and the change in revenue, where all 
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changes are estimated as the difference between the base case 

and federal plan scenario. These impacts were then summed for 

each small entity, adjusting for ownership share. An additional 

analysis was performed outside of EPA’s IPM model to estimate 

the change in demand-side energy efficiency program costs, based 

largely on IPM-projected outputs.

As noted earlier, there are 74 small entities with 

potentially affected EGUs that are modeled in the IPM base case 

in 2030. Of these, 24 small entities are projected to withdraw 

all of their potentially affected EGUs from operation under base 

case conditions. This leaves 50 small entities with potentially 

affected EGUs that are projected to be generating electricity in 

2030. Under the rate-based federal plan approach, 7 of these 50 

small entities are projected to withdraw all of their 

potentially affected EGUs from operation by 2030. Under the 

mass-based federal plan approach, 5 of these 50 small entities 

are projected withdraw all of their potentially affected EGUs 

from operation by 2030.

Under the rate-based federal plan approach, 23 small 

entities are projected to incur net compliance costs greater 

than 3 percent of generation revenues from their potentially 

affected EGUs. In contrast, 9 entities are estimated to have net 

compliance cost savings greater than 3 percent of their 
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generation revenues from affected EGUs. Under the mass-based 

federal plan approach, 21 small entities are projected to incur 

net compliance costs greater than 3 percent of generation 

revenues from their potentially affected EGUs. In contrast, 11

entities are estimated to have net compliance cost savings 

greater than 3 percent of generation revenues from their 

affected EGUs.

There are uncertainties and limitations in this analysis 

that may result in estimates that diverge from what we might see 

in reality. For example, at the time of this proposal, the EPA 

has no information on whether any or how many states will 

require a federal plan. The rate-based and mass-based federal 

plan approaches analyzed in this IRFA are based on a scenario 

where all states of the contiguous U.S. will be regulated under 

a federal plan. Another factor to consider is that entities 

operating in regulated or cost-of-service markets are likely 

able to recover compliance costs through rate adjustments; as a 

result these costs can be viewed as likely being over-estimates 

for this set of utilities. Other uncertainties and data 

limitations exist and are described in the complete IRFA 

available for review within the RIA.

As discussed earlier in this preamble, the reporting, 

recordkeeping and other compliance requirements are most likely 
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covered under Part 75 and Part 98 programs for affected EGUs. 

Therefore, only a marginal additional cost is expected for the 

monitoring, reporting and recordkeeping requirements of the 

proposed federal plan for affected EGUs.

Owners of affected EGUs may be subject to other related 

rules. For example, on September 20, 2013, EPA proposed carbon 

pollution standards for new fossil fuel fired EGUs. On June 2, 

2014, the EPA proposed carbon pollution standards for modified 

and reconstructed fossil fuel fired EGUs, in addition to the 

Clean Power Plan EGs, to cut carbon pollution from existing 

fossil fuel fired EGUs. These existing EGUs are, or will be, 

potentially impacted by several other recently finalized EPA 

rules. On February 16, 2012, the EPA issued the mercury and air 

toxics standards (MATS) rule (77 FR 9304) to reduce emissions of 

toxic air pollutants from new and existing coal- and oil-fired 

EGUs. On May 19, 2014, the EPA issued a final rule under section 

316(b) of the Clean Water Act (33 U.S.C. 1326(b)). This rule 

establishes new standards to reduce injury and death of fish and 

other aquatic life caused by cooling water intake structures at 

existing power plants and manufacturing facilities. On June 18, 

2014 (79 FR 34830), the EPA promulgated the stream electric 

effluent limitation guidelines (SE ELG) rule to strengthen the 

controls on discharges from certain steam electric power plants. 
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On April 17, 2015 (80 FR 21302), the EPA promulgated the coal 

combustion residuals (CCR) rule, which establishes technical 

requirements for CCR landfills and surface impoundments under 

subtitle D of the Resource Conservation and Recovery Act (RCRA), 

the nation's primary law for regulating solid waste.

As required by section 609(b) of the RFA, the EPA also 

convened a Small Business Advocacy Review (SBAR) Panel to obtain 

advice and recommendations from small entity representatives

that potentially would be subject to the rule's requirements.

The SBAR Panel evaluated the assembled materials and smallentity comments on issues related to elements of an IRFA. A copy 

of the full SBAR Panel Report is available in the rulemaking 

docket.

The EPA also considered whether the separate changes that 

we are proposing to make, as explained in section VII of this 

preamble above, to the framework regulations in subpart B of 

part 60 of the CAA regulations would have any impacts on small 

entities. Since these changes only modify and enhance the 

procedures that the Administrator will follow in processing 

state plans and promulgating a federal plan, and do not alter 

the rules or requirements that states or regulated entities must 

follow, the agency does not believe that there will be economic 

impacts on small entities from this portion of this proposal. 
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After considering the economic impacts of the proposed changes 

to 40 CFR 60.27, I certify those changes will not have a 

significant economic impact on a substantial number of small 

entities. 

D. Unfunded Mandates Reform Act (UMRA)

[&&&based on preliminary analysis]

This action contains a federal mandate under UMRA, 2 U.S.C. 

1531–-1538, that maycould potentially 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. 

Accordingly, the EPA has prepared the written statement required 

under section 202 of UMRAThis federal plan will apply only to 

those EGUs located in states that do not submit approvable state 

plans, which is includeda subset of the EGUs considered in the 

docketRIA for this action and briefly summarized here. 

[&&&Insert a concise summarythe final EGs (see RIA for further 

discussion of impacts). Because it is impossible to determine at 

this time which states might be ultimately subject to a federal 

plan, EPA cannot determine whether this final rule will be 

subject to UMRA. However, as noted below, the written statement 

including a brief descriptionAgency has done substantial 

outreach to government entities as part of both the 
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intergovernmental consultation.]

federal plan and the related 111(d) rulemaking. Further, 

regardless of whether EPA does determine that this action 

ultimately meets the UMRA threshold, the agency intends to do 

additional outreach with government entities between now and the 

final rule. Additionally, the EPA has determined that this 

action may significantly or uniquely affect small governments. 

The EPA consulted with small governments concerning theis not 

subject to the requirements of section 203 of UMRA because it 

contains no regulatory requirements that might significantly or 

uniquely affect them.small governments. 

Nevertheless, the EPA is aware that there is substantial 

interest in this rule among small entities (e.g., municipal and 

rural electric cooperatives). In light of this interest, prior 

to this action, the EPA sought early input from representatives 

of small entities while formulating the provisions of the 

proposed regulation. Such outreach is also consistent with the 

President’s January 18, 2011 Memorandum on Regulatory 

Flexibility, Small Business, and Job Creation, which emphasizes 

the important role small businesses play in the American 

economy. This outreach process has enabled the EPA to hear 

directly from these representatives, as EPA developed the rule 

about how the EPA should approach the complex question of how to 
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apply section 111 of the CAA to the regulation of GHGs from 

these source categories. We invite comments on all aspects of 

this proposal and its impacts, including potential adverse 

impacts, on small entities. 

E. Executive Order 13132: Federalism

[&&&based on preliminary analysis]

Under Executive Order 13132, the 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 the EPA consults with state and local 

officials early in the process of developing the proposed

action. The EPA has concluded that this action may have 

federalism implications, because it may impose substantial 

direct compliance costs on state or local governments, and the

federal government will not provide the funds necessary to pay 

those costs. As discussed in the Supporting Statement found in 

the docket for this rulemaking, [&&& Insert text consistent with 

PRA analysis].

The EPA The EPA believes that this proposed rule may be of 

significant interest to state and local governments due to its 
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relationship with the Clean Power Plan EGs. Therefore, the EPA 

has determined that consultations with state and local 

governments conducted during the Clean Power Plan EGs 

development process are also relevant to this proposed rule. 

Consistent with the EPA’s policy to promote communications 

between the EPA and state and local governments, the EPA 

consulted with state and local officials early in the process of 

developing the Clean Power Plan EGs to permit them to have 

meaningful and timely input into its development. As described 

in the Federalism discussion in the preamble to the proposed 

standards of performance for GHG emissions from new EGUs (79 FR 

1501,; January 8, 2014), the EPA consulted with state and local 

officials in the process of developing the proposed standards 

for newly constructed EGUs. A detailed Federalism Summary Impact 

Statement (FSIS) describing the most pressing issues raised in 

pre-proposal and post-proposal comments will be forthcoming with 

the final ruleClean Power Plan EGs, as required by section 6(b) 

of Executive Order 13132. In the spirit of Executive Order 

13132, and consistent with the EPA’s policy to promote 

communications between the EPA and state and local governments, 

the EPA specifically solicits comment on this proposed action 

from state and local officials.
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F. Executive Order 13175: Consultation and Coordination with 

Indian Tribal Governments

This proposed action has tribal implications. However, it will 

neither impose substantial direct compliance costs on federally 

recognized tribal governments, nor preempt tribal law. The EGU 

potentially impacted by this proposed rulemaking located on Indian 

reservations are primarily owned by private entities, and in one 

case, partially owned by an agency of the United StatesU.S.

government. As a result, the tribes on whose areas of Indian 

country those units are located will not be directly impacted by 

any costs of complying with this proposed rulemaking incurred by 

the owners/operators of those units. There would only be tribal 

implications in regards to compliance costs associated with this 

proposed rulemaking in the case where a tribal government has an 

ownership interest in a potentially affected EGU. A tribal 

government could also incur costs in the event that it seeks and 

is given delegated authority to enforce the federal plan proposed 

in this rulemaking. The EPA has, nevertheless, offered 

consultation to the tribes on whose areas of Indian country the 

units are located. As part of its general outreach to tribes 

regarding this proposed rulemaking, the EPA received feedback from 

a number of tribes regarding the potential overall economic impact 

that both the proposed Clean Power Plan and a proposed federal 
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plan rulemaking may have on them. In these instances, the EPA has 

reached out to these tribes and as part of the consultation on the 

Clean Power Plan engaged with them on their concerns regarding a 

potential federal plan. 

The EPA has conducted consultation with tribes on the Clean 

Power Plan and the Supplemental Proposal for the Clean Power 

Plan and will offer all tribes consultation on this proposed 

action. The EPA held consultations with tribes on the Clean 

Power Plan in the fall of 2014 before the agency issued its 

Supplemental Proposal for Indian Country and U.S. Territories. 

AddtionallyAdditionally, the EPA held consultations for tribes 

shortly following the release of the supplemental proposal. The 

agency also held a public hearing on the supplemental proposal 

on November 19, 2014, in Phoenix, Arizonia. At the public 

hearing the agency received oral comments from community members 

representing a number of tribes and a number of tribal officals. 

The agency also conducted consultation with tribes in the spring 

and summer of 2015. An overview of the consultations provided as 

part of the Clean Power Plan is available in section XII.F of 

the final Clean Power Plan rulemaking.EGs.

Additionally, the EPA engaged in meaningful dialogue with 

tribal stakeholders to obtain their feedback in the prepropsalproposal stages of this rulemaking. We provided an update 
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on this proposed rulemaking on the May 28, 2015, National Tribal 

Air Association (NTAA) and the EPA Air Policy call. 

Additionally, staff attended the National Tribal Forum 

conference on May 20, 2015 and provided an overview of the Clean 

Power Plan and explained that the agency would be proposing a 

fededral plan. certification is included in the docket for this 

action.federal plan. 

Consistent with previous rulemakings impacting the power 

sector, there is significant tribal interest in these 

rulemakings because of the potential indirect impacts that rules 

such as the Clean Power Plan and this proposed federal plan may 

have on tribes. The EPA specifically solicits additional 

feedback from tribal officials on all aspects of this proposed 

rulemaking, including whether tribes whose areas of Indian 

country contain affected EGU(s) are interested in developing 

their own plan implementing the final emission guidelines.EGs.

Additionally, tribal stakeholders will be included in the 

outreach that the agency will be conducting with those 

communities already overburdened by pollution, which are often 

low-income communties, communities of color, , and indigenous 

communities. The actions that the agency will be takingngtaking

are outlined in section XIIX of this preamble.
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G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks

The EPA interprets EO 13045 (62 FR 19885, April 23, 1997) 

as applying to those regulatory actions that concern health or 

safety risks, such that the analysis required under section 5–

501 of the Order has the potential to influence the regulation. 

This action is not subject to EO 13045 because it does not 

involve decisions on environmental health or safety risks that 

may disproportionately affect children. The EPA believes that 

the CO2 emission reductions resulting from implementation of the 

proposed guidelines, as well as substantial ozone and PM2.5 

emission reductions as a cobenefit, would further improve 

children’s health.

H. Executive Order 13211: Actions That Significantly Affect 

Energy Supply, Distribution, or Use

This action, which is a significant regulatory action under 

EO 12866, is likely to have a significant effect on the supply, 

distribution, or use of energy. The EPA has prepared a Statement 

of Energy Effects for this action as follows. We estimate a 1 to 

2 percent change in retail electricity prices on average across 

the contiguous U.S. in 2025, and a 22 to 23 percent reduction in 

coal-fired electricity generation as a result of this rule. The 

EPA projects that utility power sector delivered natural gas 
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prices will increase by up to 2.5 percent in 2030. For more 

information on the estimated energy effects, please refer to the

economic impact analysis for this proposal. The analysis is 

available in the RIA, which is in the public docket.

I. National Technology Transfer and Advancement Act (NTTAA)

This proposed action does not involve technical standards. 

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations 

Executive Order 12898 (59 FR 7629; February 16, 1994) 

establishes federal executive policy on environmental 

justice.EJ. Its main provision directs federal agencies, to the 

greatest extent practicable and permitted by law, to make 

environmental justiceEJ part of their mission by identifying and 

addressing, as appropriate, disproportionately high and adverse 

human health or environmental effects of their programs, 

policies, and activities on minority populations and low-income 

populations in the U.S. The EPA defines environmental justiceEJ

as the fair treatment and meaningful involvement of all people 

regardless of race, color, national origin, or income with 

respect to the development, implementation, and enforcement of 

environmental laws, regulations, and policies. The EPA has this 
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goal for all communities and persons across this Nation. It will 

be achieved when everyone enjoys the same degree of protection 

from environmental and health hazards and equal access to the 

decision-making process to have a healthy environment in which 

to live, learn, and work.

Leading up to this rulemaking the EPA summarized the public 

health and welfare effects of GHG emissions in its 2009 

Endangerment Finding. As part of the Endangerment Finding, the 

Administrator considered climate change risks to minority 

populations and low-income populations, finding that certain 

parts of the population may be especially vulnerable based on 

their characteristics or circumstances. Populations that were 

found to be particularly vulnerable to climate change risks 

include the poor, the elderly, the very young, those already in 

poor health, the disabled, those living alone, and/or indigenous 

populations dependent on one or a few resources. See sections 

XXX.F and XXX.G of this preamble, above, where the EPA discusses 

Consultation and Coordination with Tribal Governments and 

Protection of Children. The Administrator placed weight on the 

fact that certain groups, including children, the elderly, and 

the poor, are most vulnerable to climate-related health effects.

The record for the 2009 Endangerment Finding summarizes the 

strong scientific evidence in the major assessment reports by 
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the U.S. Global Change Research Program (USGCRP),, the 

Intergovernmental Panel on Climate Change (IPCC), and the 

National Research Council (NRC) of the National Academies that 

the potential impacts of climate change raise environmental 

justiceEJ issues. These reports concluded that poor communities 

can be especially vulnerable to climate change impacts because 

they tend to have more limited adaptive capacities and are more 

dependent on climate-sensitive resources such as local water and 

food supplies. In addition, Native American tribal communities 

possess unique vulnerabilities to climate change, particularly 

those impacted by degradation of natural and cultural resources 

within established reservation boundaries and threats to 

traditional subsistence lifestyles. Tribal communities whose 

health, economic well-being, and cultural traditions that depend 

upon the natural environment will likely be affected by the 

degradation of ecosystem goods and services associated with 

climate change. The 2009 Endangerment Finding record also 

specifically noted that Southwest native cultures are especially 

vulnerable to water quality and availability impacts. Native 

Alaskan communities are already experiencing disruptive impacts, 

including coastal erosion and shifts in the range or abundance 

of wild species crucial to their livelihoods and well-being. 

The most recent assessments continue to strengthen 
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scientific understanding of climate change risks to minority 

populations and low-income populations in the United 

StatesU.S.160 The new assessment literature provides more 

detailed findings regarding these populations’ vulnerabilities 

and projected impacts they may experience. In addition, the most 

recent assessment reports provide new information on how some 

communities of color may be uniquely vulnerable to climate 

 

160 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, 

Eds., 2014: Climate Change Impacts in the United States: The Third 

National Climate Assessment. U.S. Global Change Research Program, 

841 pp. 

IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and 

Vulnerability. Part A: Global and Sectoral Aspects. Contribution 

of Working Group II to the Fifth Assessment Report of the 

Intergovernmental Panel on Climate Change [Field, C.B., V.R. 

Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. 

Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. 

Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White 

(eds.)]. Cambridge University Press, 1132 pp.

IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and 

Vulnerability. Part B: Regional Aspects. Contribution of Working 

Group II to the Fifth Assessment Report of the Intergovernmental 

Panel on Climate Change [Barros, V.R., C.B. Field, D.J. Dokken, 

M.D. Mastrandrea, K.J. Mach, T.E. Bilir, M. Chatterjee, K.L. Ebi, 

Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. 

MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. Cambridge 

University Press, 688 pp.
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change health impacts in the United StatesU.S. These reports 

find that certain climate change related impacts—including heat 

waves, degraded air quality, and extreme weather events—have 

disproportionate effects on low-income populations and some 

communities of color (in particular, populations defined jointly 

by ethnic/racial characteristics and geographic location), 

raising environmental justiceEJ concerns. Existing health 

disparities and other inequities in these communities increase 

their vulnerability to the health effects of climate change. In 

addition, assessment reports also find that climate change poses 

particular threats to health, well-being, and ways of life of 

indigenous peoples in the United States.U.S.

As the scientific literature presented above and as the 

2009 Endangerment Finding illustrates, low income populations 

and some communities of color are especially vulnerable to the 

health and other adverse impacts of climate change. The EPA 

believes that communities will benefit from this proposed 

federal plan because this action directly addresses the impacts 

of climate change by limiting GHG emissions through the 

establishment of CO2 emission standards for existing affected 

fossil fuel-fired EGUs. 

In addition to reducing CO2 emissions, the guidelines 

finalized in this rulemaking would reduce other emissions from 
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affected EGUs that reduce generation due to higher adoption of 

energy efficiencyEE and renewable energyRE. These emission 

reductions will include SO2 and NOx, which form ambient PM2.5 and 

ozone in the atmosphere, and hazardous air pollutants (HAP),,

such as mercury and hydrochloric acid. In the final rule 

revising the annual PM2.5 NAAQS,161 the EPA identified low-income 

populations as being a vulnerable population for experiencing 

adverse health effects related to PM exposures. Low-income 

populations have been generally found to have a higher 

prevalence of pre-existing diseases, limited access to medical 

treatment, and increased nutritional deficiencies, which can 

increase this population’s susceptibility to PM-related 

effects.162 In areas where this rulemaking reduces exposure to 

PM2.5, ozone, and methylmercury, low-income populations will also 

benefit from such emissions reductions. The RIA for this 

rulemaking, included in the docket for this rulemaking, provides 

additional information regarding the health and ecosystem 

 

161 “National Ambient Air Quality Standards for Particulate Matter, 

Final Rule,” 78 FR 3086 (Jan. 15, 2013).

162 U.S. Environmental Protection Agency (U.S. EPA). 2009. 

Integrated Science Assessment for Particulate Matter (Final 

Report). EPA-600-R-08-139F. National Center for Environmental 

Assessment – RTP Division. December. Available on the Internet at 

http://www.cfpub.epa.gov/si/si_public_record_Report.cfm?dirEntry

Id=216546.
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effects associated with these emission reductions. 

Additionally, as outlined in the community and environmental 

justiceEJ considerations section IX of this preamble, the EPA has 

taken a number of actions to help ensure that this action will not 

have potential disproportionately high and adverse human health or 

environmental effects on vulnerable communities. The EPA consulted 

its May 2015, Guidance on Considering Environmental Justice During 

the Development of Regulatory Actions, when determining what 

actions to take.163 As described in the community and environmental 

justiceEJ considerations section of this preamble the EPA also 

conducted a proximity analysis, which is available in the docket 

of this rulemaking and is discussed in section IX. of this 

preamble. Additionally, as outlined in sections I and IX of this 

preamble the EPA has engaged meaningfully with communities 

throughout the development of the CPP and has devised a robust 

outreach strategy for continual engagement throughout this 

rulemaking.

 

163 Guidance on Considering Environmental Justice During the 

Development of Regulatory Actions. 

http://www.epa.gov/environmentaljustice/resources/policy/conside

ring-ej-in-rulemaking-guide-final.pdf. May 2015.
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List of Subject in 40 CFR Part 62

Environmental protection, Administrative practice and 

procedure, Air pollution control, Intergovernmental 

relations, Reporting and recordkeeping requirements.

Dated: _________________.

________________________

Gina McCarthy,

Administrator.