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During Review***

EO12866_CPP Federal Plan 2060 AS47 NPRM_2015070220150801

6560-50-P

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 RuleRules; Amendments to 

Framework Regulations

AGENCY: Environmental Protection Agency (EPA)..

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 

emission trading program and a mass-based emission trading 
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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 

regulations related to the process and timing for state plan 

submissions and EPA actions. The EPA intends to finalize both 
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the rate-based and mass-based model trading rules in summer

2016.

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

date 45 DAYS FROM90 days after date of publication in the

Federal Register]. 

Public Hearing. If anyone contacts the EPA by [INSERT DATE 

10 DAYS FROM DATE OF PUBLICATION IN THE FEDERAL REGISTER] 

requesting to speak at a public hearing, the EPA will hold a 

public hearing on [INSERT DATE 15 DAYS FROM DATE OF PUBLICATION 

OF THIS PROPOSED RULE IN THE FEDERAL REGISTER]. 

Public Hearing. The EPA will be holding [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 [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 A-and-RDocket@epa.gov, Attention Docket ID No. EPA-HQ-OAR-2015-

0199.

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

Docket ID No. EPA-HQ-OAR-2015-0199.
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• Mail: Send your comments to: EPA Docket Center (EPA/DC), 

Environmental Protection Agency, EPA Docket Center 

(EPA/DC), Mailcode: 28221T, 1200 Pennsylvania Ave., NW, 

Washington, DC 20460, Attention Docket ID No. EPA-HQ-OAR2015-0199. 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 

comment. If you send an email comment directly to the EPA 
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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: [insert number of hearings here] public 

hearings will be held to accept oral comments on the proposed 

federal plan. The hearings will be held on [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 to 

speak at a hearing, please use the online registration form 

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

regarding registration, please contact [insert name] at (919)

541–[insert number]. The last day to pre-register to speak at 

the hearings will be [insert date], 2015. Additionally, requests 

to speak will be taken the day of each hearing at the hearing 
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registration desk, although preferences on speaking times may 

not be able to be fulfilled. Please note that registration 

requests received before each 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 their requested time 

is taken. Please note that the time outlined in the confirmation 

email received will be the time the one will be scheduled to 

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

fluctuate. If you require the service of a translator or special 

accommodations such as audio description, we ask that you preregister for the hearings by [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.Public Hearing: If a public 

hearing is held, it will be held at [&&&XX]. Contact Ms. Aimee 

St. Clair at (919) 541-1063, to request a hearing, to request to 

speak at a public hearing or to determine if a hearing will be 

held. If no one contacts the EPA requesting to speak at a public 

hearing concerning this proposed rule by [INSERT DATE 10 DAYS 

FROM DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL 

REGISTER], the hearing will be cancelled without further notice.
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While the EPA expects the hearings to go forward as set 

forth above, we ask that you monitor our Web site or contact 

[insert name] at (919) 541–[insert number] to determine if there 

are any updates to the information on the hearings. The EPA does 

not intend to publish a notice in the Federal Register

announcing any such updates. The hearings 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 hearings 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 
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2005, established new requirements for entering federal 

facilities. If your driver’s license is issued by Alaska, 

American Samoa, Arizona, Kentucky, 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 
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screening. Additionally, no weapons (e.g., pocket knives) or 

drugs or drug paraphernalia (e.g., marijuana) will be allowed in 

the building. We recommend 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 
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(E143-05), Environmental Protection Agency, Research Triangle 

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

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
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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 

Organization

lbs 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

OAQPS Office of Air Quality Planning and Standards

PPA Power Purchase Agreement

PRA Paperwork Reduction Act

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
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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

1. The Rate-based Approach

2. The Mass-based Approach

3. Other Proposed Actions

C. Who Does the Proposed Action Apply to?

1. What is an Affected Electric Utility Generating Unit?

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

Effective State Plan

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

II. Background Information

A. What is the Regulatory Development Background for this 

Proposed Rule?

B. What is the Purpose of this Proposed Rule?

1. Federal plan

2. Model Trading 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

1. Interactions with State Plans and scope of trading

2. Addressing Potential Leakage and Interstate Effects

3. Provisions to Encourage Early Action

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

1. Title V Permitting

2. Implications for New Source Review Program

I. Administrative Appeals Process

J. Consistency of Program Structure with Clean Air Act Authority

1. General Section 111(d)(2) Authority
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2. Use of Market Techniques to Implement Standards of 

Performance under the Clean Air Act

IV. Rate-based Implementation Approach

A. Overview

B. Rate Goals

C. Crediting Mechanism

1. ERCs Generated and Owed Against a Standard

2. Incremental NGCC ERCs

3. Eligible Emission Reduction Measures for ERC Generation

D. ERC Tracking and Compliance Operations

1. Designated Representatives and Alternate Designated 

Representatives

2. ERC Tracking and Compliance System

3. Tracking System Requirements

4. Compliance and General Accounts

5. Compliance Demonstration

6. Recordation of ERC Generation and ERC Issuance

7. Independent Verifiers

8. Evaluation, Measurement, and Verification (EM&V) Plans, 

Monitoring and Verification (M&V) Reports, and Verification 

Reports

Submittals

9. ERC Transfers and Trading

10. Compliance with Emissions Standards

11. Other ERC Tracking and Compliance Operations Provisions

12. Banking of ERCs

13. Emissions Monitoring and Reporting

E. Federal Plan and State Plan Interactions

1. Interstate Trading

2. Treatment of States Entering or Exiting the Trading Program.

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

1. Proposed Allocation Approach and Alternatives

2. Timing of Allowance Recordation

3. Allowance Set-asides to Address Leakage to New Sources

4. Provisions to Encourage Early Action

5. Allocations to Units that Change Status

D. State-determined Allowance Distribution

E. Treatment of States Entering or Exiting the Trading Program

F. Allowance Tracking, Compliance Operations, and Penalties

1. Designated Representatives and Alternate Designated 

Representatives
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2. Allowance Tracking and Compliance System

3. Compliance and General Accounts

4. Recordation of Allowance Allocations and Transfers

5. Compliance with Emissions Limitations

6. Other Allowance Tracking and Compliance Operations Provisions

G. 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

1. Federal Plan Becomes Effective Prior to Approval of a State 

or Tribal Plan

2. State or Tribe Takes Delegation of the Federal Flan

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 
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Executive Order 13563: Improving Regulation and Regulatory 

Review

B. Paperwork Reduction Act (PRA)

C. Regulatory Flexibility Act (RFA)

D. Unfunded Mandates Reform Act (UMRA)

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 Environmental Protection AgencyEPA and the states.

Under section 111(d) of the Clean Air Act (CAA),, the 

Environmental Protection Agency (EPA) establishes emission 

targetsperformance levels based on its determination of the BSER

for existing sources of air pollution and provides guidelines 

for state plans to apply the emission targetsstandards of 

performance to their sources. that meet the BSER level of 

performance. The EPA has promulgated these Emission Guidelines

(EGs) under CAA section 111(d),) which setsset 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 these EGs to 
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their sources in developing state plans. The EGs 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, in lieu of plans, initial 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 and will not be penalized for failing to participate in 
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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 

federal plan for only the affected EGUs in states that the EPA 

determines did not submit an approvable plan. 
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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 only a given state in the event that 

the state fails todoes 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 submitted plan because it does not meet the 
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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 today’s proposalthis 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 is strongly considering takingcurrently 

intends to finalize a single approach (i.e., either the massbased or rate-based approach) for every state in which it 

promulgates a federal plan, and we are inviting comment ongiven 

the benefits of a broad trading program, as discussed in the 

following section of this preamble. We also invite comment on 

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

should be selected if we opt to finalize a single 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 

 

1 For simplicity, at times this document may refer to the co-proposed 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 rate-based 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 state-specific “federal 

plans.” This is consistent with the agency’s prior practice in other multistate 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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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 a full or partial 

delegation of administrative aspects of the federal plan in 

order to become the primary implementers. And as discussed in 

section &&&,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 allowancedistribution 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 

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 
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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 

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 

 

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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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 

&&§ion 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 

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. These proposed changes are 

discussed in &&§ion VII.Finally, the agency proposes to 
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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, and, importantly,

on. The agency gave extensive consideration to impacts on 

vulnerable communities, particularly low-income communities and,

communities of color., and indigenous communities. These 

considerations are generally 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). In section 

&&&XVarious 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 
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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- andbased 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-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 
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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/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 ensure 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 

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. 
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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 overburdenedvulnerable communities. In the 

process of 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 overburdened

communities. The goal of these outreach activities is to provide 

communities with the information they need to understand how the 
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proposed rulemaking will potentially impact their respective 

communities. At the same time, this information will be useful 

in helping overburdened 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 overburdenedvulnerable

communities, which are outlined in the community and 

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

this preamble.

B. Organization and Approach for this Proposed Rule

In today’sthis 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 

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.
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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 today’s proposalthis

proposed rule by summer 2016, prior to the deadline for state 

submittals.

The EPA is currently considering finalizing onlyintends 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, ensure efficient administration 

of the program, and simplify compliance options for affected 

EGUs. However, the EPA recognizes thatThe 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 
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with mass-based trading programs. The EPA has more than two 

decades of experience implementing federally-administered massbased 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 rate-based 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. Therefore, we are 

inviting comment on whether the agency should The EPA recognizes 

that it remains potentially possible to finalize only onea 

different approach for all states that may become subject to 

theto a federal plan (and which approach that should be), or 

whether a rate-based or mass-based approach should be selected 

based on the uniquein some circumstances of each state, but 

believes that in general, and consistent with prior federal 

trading programs such as CSAPR, creating a single, broad program 

has the most 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 
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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 today’sthis 

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 

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 

 

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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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 that 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 twothree proposed allowance set-asides – to 

the affected EGUs based on their historichistorical generation. 

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 twothree set-asides of 
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allowances: one(1) For a Clean Energy Incentive Program; (2) to 

support renewable energyRE projects; and the other(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 mass-based 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 today’sthis action, the EPA is also proposing a number 

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

Subpart B of 40 CFR part 60, subpart B. These changes generally 

are intended to provide enhancements to the process for state 

plan submissions and the 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 
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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 Emission Guidelines 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 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: 

 

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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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 

criteria in 40 CFR &&&62.XXX to 62.XXX60.5845 and 60.5850 of 

subpart MMM being proposed todayUUUU. 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 Emission Guidelines (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 
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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 

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

 

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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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 

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 thea Federal Register notice announcingregarding

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 

 

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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accordance with the Presidential Memorandum7, as well as the 

benefit of providing statestates 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 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?

Submitting CBI

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. 

EPA-HQ-OAR-2015-0199. Clearly mark the part or all of the 

 

7 Presidential Memorandum—Power Sector Carbon Pollution Standards, June 25, 

2013. http://www.whitehouse.gov/the-press-office/2013/06/25/presidentialmemorandum-power-sector-carbon-pollution-standards.
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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 

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 

http://wwwwww2.epa.gov/airtoxics/XX. The TTN provides 

information and technology exchange in various areas of air 
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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. 

II. Background Information

A. What is the Regulatory Development Background for this 

Proposed Rule?

On &&&July 31August 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 

emission guidelines.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 

&&&).part 60, subpart UUUU).8 As discussed in section &&&VI.D of 

 

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.
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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 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 

 

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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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 

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 
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EPA by August 31September 6, 2016 that are at least as 

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 noticeparticipation 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 

arewould 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 trading rule, so long as they still meet the requirements 
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of the EGs. If the state chooses to tailor or modify the model 

trading rule – for instance,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 

appropriate review of such provisions for consistency with the 

EGs would need to be conducted., 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). 

Recognizing the amount of time 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 
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rulemaking process. Without prejudging the outcome of that 

process, the EPA recognizes that it may take for some statesbe 

able to go through their decision making processes, the EPA 

intends toapprove or “conditionally approve” state plans that 

adopt one of the model trading rules as proposed. This provides 

states an immediate additional pathway to an ultimately 

approvable state plan. The condition for approval of a state 

plan based on one of the proposed model rules, is that the state 

commit to adoptare substantially similar, but not identical to,

the final model trading rule, when it is finalized, or submit 

materials explaining why any changes to the final rule are not 

being adopted, and demonstrating that 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 plan based on the proposed model trading rule 

continuestake 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 &&§ion 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 
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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 

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 
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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 

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 
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model trading rule, which, again, also serves as the proposed 

federal plan, 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 

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 Regulations,CFR, 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

 

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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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 

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

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, 
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Region Regional contact Phone

States and 

protectorates

Northern Mariana 

Islands

Region X Madonna Narvaez

narvaez.madonna@epa.g

ov

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 

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 2-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 

fails todoes not submit a final state plan or initial plan 
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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 

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

Today’sThis 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 

 

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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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 2 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 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 

 

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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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 today’sthis 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 

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 60.5760,5765, the

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

a state that its initial submittal does not meet the 
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requirements of 60.5760(a). As with state plans, the EPA will 

have twelve12 months from the date of a state's initial 

submittal to promulgate a federal plan forfrom the affected EGUs 

in statesdate 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

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 Federal 

Implementation PlanFIP “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. Where, as here, It is 

essential to implement plans for the control of emissions of

carbon dioxideCO2 expeditiously, and avoid unnecessary delay. 
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Among other reasons, this will provide affected EGUs regulatory 

certainty, and avoid any unnecessary delay 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. In addition, this 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.

It is the agency’s intention to promulgate federal plans 

promptly for states who do not submit plans or initial

submittals by 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 
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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,

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 final model trading rules,two subparts proposed in 

this action (if finalized), along with any applicable 

 

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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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 (Aug.; 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 

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 &&&Sectionsections

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

 

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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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 emission guidelinesEGs,

and identify all necessary state 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 
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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 

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 
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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 

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.

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 

 

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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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 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 and the state havehas 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 
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or a state meeting the conditions for linkage to the federal 

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-forinterstate-trading” 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-forinterstate-trading. The EPA proposes to allow interstate trading 

between sourcesaffected EGUs in states covered by the proposed 

federal plans and sourcesaffected EGUs in states covered by 

state plans (referred to below as “linking” states, or 
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“linkages”) under the following conditions, which are discussed 

further below the list:

• 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 couldcan link to mass-based trading programs only,

and rate-based trading programs couldcan 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 i1) 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 ii2) 

from sourcesaffected EGUs in such state-plan-covered states to 

sourcesaffected 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 ratebased trading state plan meeting the proposed conditions for 
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linkages and that uses an EPA-designated 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 

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; as a result, the EPA 

is proposing in this rule that linkage for the mass-based 

federal plan is limited to state plans that issue allowances in 

short tons. The agency also requests comment on whether to 
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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 state 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 

conditions for linkages and that uses an EPA-designated 

allowance tracking systemssystem that is interoperable with an 

EPA-administered 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 

 

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

noted.
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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 [&&& cite to final EGs preamble section]. (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 

greater opporunitiesopportunities 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.
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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.

Interstate Effects and Addressing Potential Leakage

The final Emission Guidelines recognized that emission 

reduction measures will likely have impacts beyond their borders 

because of the interstate nature of the grid (see final emission 

guidelines Sec. VIII.L for a detailed discussion of interstate 

effects and addressing potential leakage). Interstate effects and 

leakage could interfere with meeting reduction obligations under 

federal and state plans, usually because of dynamics resulting

from the regional grid existing in combination with differences in 

state-based characteristics, including the portfolio of affected 
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EGUs within a particular state, the availability of eligible state 

measures, existing policies in the state and the cost of compliance 

in the state. In the final Guidelines, 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 goals under 

a state plan. In fact, the final guidelines are premised in part 

on reductions due to the movement of generation from higheremitting to lower-emitting affected EGUs. However, the risk of 

foregone emission reductions due to the moveement of generation 

should be minimized. The final guidelines also discussed how the 

use of the sub-categorized uniform emission rates for steam and 

gas, and the state plan requirements (particularly their approach 

to accounting for measures that cross state boundaries), serve to 

reduce the risk of interstate effects.

The final guidelinesA transparent and well-functioning 

allowance or ERC market is an important element of a mass-based 

or rate-based trading program. The EPA has over 20 years of 

experience implementing 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 
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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. Addressing Potential Leakage and Interstate Effects

The 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 of the BSER (e.g., the ratebased and mass-based state goals) to 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 incorporating the 

subcategory-specific emission performance rates representing the 

BSER. The final EGs specified that mass-based plan approaches 

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 
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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, the final EGs ensure that mass goals are 

equivalent to the CO2 emission performance rates and 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 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 set-aside that 

encourages the installation of RE. These proposed strategies are 

detailed in section V.D of this preamble.

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 rate-based approach, in accordance with the final 
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guidelines, requires thatrestricts ERC issuance for any emission 

reduction measures located in a mass-based state, except for RE.

RE measures 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 electricity generated is delivered 

withrate-based state have contracted for the intentiondelivery 

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

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

plan, we are proposing that this can be demonstrated through: 1)

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 2)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 MWh submitted 

are achieved by an approved project located in a mass-based 

state. The EPA requests comment on this approachassociated with 

that contractual arrangement with the mass-based RE provider.

The EPA requests comment on this approach. It should also be 
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noted that we are proposing that under the proposed mass-based 

approach, if RE located in a mass-based state receives massbased set-aside allowances for any generation, that generation 

is not eligible to be issued ERCs in a rate-based state.

Under the proposed mass-based approach there is a restriction 

to counting RE that is located in a mass state in a rate-based 

system: RE providers that receive mass-based set-aside allowances 

for their generation are barred from having ERCs issued for that 

generation in a rate-based state.

Under the proposed mass-based approach, double counting due 

to interstate effects is minimized because compliance with mass 

goals is based only on stack emissions. However, mass-based 

states face the problem of generation shifting to unaffected 

sources, particularly new generation, if the plan does not 

include new generation under a cap) that operate within the 

state but outside of the mass cap. This is much less of a 

concern under rate-based plan, and thus could mean that massbased goals and CO2 performance rates (along with associated 

rate-based goals) may not be equivalent if leakage is not 

addressed. Therefore, the final emission guidelines require 

that mass-based plans make a demonstration that leakage to new 

unaffected EGUs has been sufficiently addressed. To meet this 

requirement in the mass-based federal plan, the EPA is proposing 

allocation options that mitigate leakage to new unaffected EGUs. 
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Specifically, the EPA is proposing to implement output-based 

allocation, which reserves some allowances to be allocated to 

affected EGUs based, in part, on their level of electricity 

generation in a recent period(s). Therefore, the allocations are 

not fixed, but instead update over time depending on an affected 

EGU’s generation. Affected EGUs can increase their allowance 

allocation based on their generation, which incentivizes 

generation to remain under the mass, thereby helping to avoid 

leakage of generation to unaffected EGUs. Additionally, a setaside awarding allowances for RE generation is being proposed, 

which can make more RE available in states with a mass-based 

federal plan, and increase the amount of low-emitting generation 

available in the states. The need to address leakage and both of 

the proposed set-asides are discussed in detail in Sec. 

&&&V.D.3. The EPA takes comment on both the set-aside for 

output-based allocation and the set-aside of allowances for RE 

generation.

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. 

Applicability and Inventory of Affected Units

[&&&under developments]
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Inventory, and as part of Emissions

[&&& under development]

Compliance Schedule

In accordance with the schedule set out in the Emission 

Guidelines, the 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, unless there is a need to modify later, such as future 

EPA action amending the EGs. 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 (three calendar years). The second 

compliance period will be from January 1, 2025 to midnight, 

December 31, 2027 (three calendar years). The third compliance

period will be from January 1, 2028 to midnight, December 31, 

2029 (two calendar years).proposed model rules. 

3. Provisions to Encourage Early Action

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

These RE projects must commence construction, and these EE 

projects must commence implementation after the date of 

submission of a final plan to the EPA by the state they are 

located on or benefitting, 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 

subject to either a rate-based or mass-based federal plan. The 

EPA’s proposed approaches to implementing the program in the 

rate-based and mass-based federal plans are detailed in sections 

IV and V of this preamble, respectively.

B. Inventory of Emissions

Fossil fuel-fired 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 fuel-fired 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 
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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 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 3 of this preamble, which presents 

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

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

 

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

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

underground or deep sea reservoirs of CO2.
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Table 3. 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 and Product 

Use 342.1 367.4 359.1

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 all energy-related CO2 emissions.25 Table 4

 

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.

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.

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.
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of this preamble presents total CO2 emissions from fossil fuelfired EGUs, for years 1990, 2005, and 2013.

Table 4. 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, 

which represents comprehensive total U.S. GHG emissions and 

complies with commitments under the UNFCCC, the EPA collects 

detailed GHG emissions data from the largest emitting facilities 

in the U.S. through its 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 5 of this preamble presents total 

GHG emissions in 2013 for the largest emitting industrial 

sectors as reported to the GHGRP. As shown in Table 4 and Table 

5 of this preamble, respectively, CO2 emissions from fossil fuelfired EGUs are nearly three times as large as the total reported 

 

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 fuel-fired 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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GHG emissions from the next ten largest emitting industrial 

sectors in the GHGRP database combined.

Table 5. Direct GHG Emissions Reported to GHGRP by Largest 

Emitting Industrial Sectors (MMT CO2e)27

Under the Emission Guidelines, 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 two 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 EPA through a 

revision to the federal plan or other action.28

The EPA recognizes that the compliance periods provided for 

 

27 U.S. EPA Greenhouse Gas Reporting Program Dataset as of August 18, 2014. 

http://ghgdata.epa.gov/ghgp/main.do.

28 This schedule would be the same under either a rate- or mass-based 

approach. 

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

Food Processing Facilities 30.8
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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.

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 compliance period in 2022. 

The EPA requests comment on whether there is any reason to

use shorter compliance periods than the proposed periods, and 

how modifying these periods could be done in a manner that is 

consistent with the Emission Guidelines. To the extent this 

schedule is governed by the schedule set in the final EG, the 
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agency is not re-opening such issues, and comments regarding the 

schedule finalized in the EG will be considered out of scope. 

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, 2014,29 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). 

 

29 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).
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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 Emission GuidelinesEGs are those 

that (1) Are subject to subpart 40 CFR part 60, 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-third or less of its 
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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 unitCHP 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 
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industrial solid waste incineration unit that is subject to 

subpart CCCC of 40 CFR part 60.30

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 

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 

 

30 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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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 Emission 

Guidelines.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 is 

applicablewere 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 

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, 
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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 (3 

calendar years). The second compliance period will be from 

January 1, 2025 to midnight, December 31, 2027 (3 calendar 

years). The third compliance period will be from January 1, 2028 

to midnight, December 31, 2029 (2 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 2 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 to the 

federal plan or other action.31

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 

 

31 This schedule would be the same under either a rate- or mass-based 

approach. 
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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 

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 EGs 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 
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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 washas been designed to ensure 

that, to the greatest extent possible, implementation would not 

interfere with the power sector’s ability to maintain electric 

reliability.32 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 

 

32 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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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 

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 
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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.33 Long-term system 

planning happens at both the local and regional levels with all 

segments of the electric system needing to operate together in 

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.34 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.35

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 

 

33 Casazza, J. and Delea, F., Understanding Electric Power Systems: An 

Overview of the Technology, the Marketplace, and Government Regulations, IEEE 

Press, at 160 (2010).

34 Id.

35 NERC Reliability Standard EOP-001-2.1b — Emergency Operations Planning, 

available at http://www.nerc.net/standardsreports/standardssummary.aspx.
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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 

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.
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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 

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 
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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 

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 massbased 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. 
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The set-aside would be in addition to the proposed setasides that are detailed in section V.D in this preamble. The 

EPA would set aside allowances in each state under the massbased federal plan, and if a reliability issue is perceived by 

the EPA, DOE and 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 set-aside. 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 CEIP, which was established in the 

EGs to reward investment in certain clean energy projects that 

achieve MWh results during 2020 and 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 
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plans, respectively). Implementation of the Clean Energy 

Incentive Program in the federal plans would create ERCs and 

allowances before 2022, allowing for 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 EGEGs, 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 

Emission GuidelinesEGs, 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-wide targets 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 the requirement that the EPA itself, in the design 
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of its federal plan, consider, among other factors, the 

remaining useful lives of the affected facilities. The agency 

therefore proposes anthe following analysis of this factor in 

&&§ion III.G.1..36

In section III.G.2, we discuss a related concern raised by 

some stakeholders, which is whether the federal plan could 

result in widespread “stranded assets” as a direct result of the 

rule. As explained below in &&§ion III.G.2, we believe this 

concern is distinct from the the “remaining useful lives” factor 

Congress directed the agency to consider in section 111(d)(2). 

Nonetheless, we undertook analysis of whether and to what extent 

there may be a “stranded asset” concern. We believe our analysis 

demonstrates that this is not likely to be a widespread issue 

under the federal plan. We request comment on this, as well as 

all other aspects of this discussion.

 

36 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-HQ-OAR-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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Consideration of Remaining Useful Lives

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 

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 of the physical age 

offor facilities. As explained below, we believe 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.
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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 liveselives” factor is considered. The statute

does not require, and Congress did not intend, that this 

consideration mandate the agency to prevent all premature 

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. 
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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 

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 ocstscosts, 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 
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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 in that the plan does 

not mandate that plants with short remaining useful lives must

install costly, capital-intensive pollution control upgrades.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 multiyear 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 initial years of the program. 

These tools will create economic incentives that reward overperformance 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 
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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.37 The design of the federal plan as a form of emission 

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 

 

37 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, facilityspecific variances from an otherwise applicable standard of performance have 

been potentially available under the application process in 40 CFR 

60.27(e)(2), 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 facilityspecific 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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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 

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 using a step-down approach, orfollowing 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 multiyear 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 Emission GuidelinesEGs, and, as explained in the EGs,

the Guidelines reflect a reasonable, rather than a maximum 
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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 achievable by collective 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.38 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.

Potential for Stranded Assets

While we believe the analysis above satisfies the 

consideration of remaining useful lives in this proposed federal 

plan, the agency in its discretion has also considered a 

different, but related problem, which has been raised by some 

 

38 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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commenters and stakeholders on the CPP EGs. This is the concern

that the CPP will force or mandate the premature retirement of 

affected units which have extended remaining useful lives (i.e., 

the CPP should not result in stranded assets). For the reasons 

presented in this section, we do not believe these concerns are 

warranted with respect to the proposed federal plan. The 

analysis presented here is meant to demonstrate that, on the 

whole, the federal plan is not anticipated to force or result in 

widespread stranded assets.

[&&&final analytics results needed here***]

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 

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 71.39 All major stationary sources 

 

39 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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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 

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.
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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 

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 
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addressed in title V permits.”40 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 theirits existing title V permit, or obtain a new 

permit if 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 

 

40 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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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 

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 
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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 maycould 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 rareinfrequent. 

As 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 an operationala change 

that would violatego 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 
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permit, but this principle is important to keep in mind when 

deciding if a minor permit modification is neededappropriate

with respect to operating a trading program in the context of a 

title V permit.

As new applicable requirements under title V, the 

requirements for covered units under the proposed federal plan 

will need to be incorporated into covered sources’ existing 

title V permits either pursuant to the provisions for reopening 

for cause (40 CFR 70.7(f) and 40 CFR 71.7(f)) or the permit 

renewal provisions (40 CFR 70.7(c) and 71.7(c).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 onfor

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 permit that 

would be issued pursuant to 40 CFR 70.7(a) willor 71.7(a) would

address the federal plan requirements, when finalized.

The EPA notes that the approach to title V permitting that 

it is proposing todaybeing proposed is verysomewhat 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 
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issued guidance to assist permitting authorities and sources 

subject to CSAPR in incorporating CSAPR requirements into title 

V permits.41 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 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 

 

41 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 Cross-State Air Pollution Rule (May 13, 2015).
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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 EG, &&&[citation],final EGs, 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 

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 
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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 an increase in annuala 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 

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 
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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 today’sthis

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

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 rules.42.

These rules include the Mercury and Air Toxics Standards (MATS) 

 

42 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 requirements because of other upcoming 

regulations.
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(77 FR 9304; Feb. 16, 2012));43; 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 Emission GuidelinesEGs 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. J

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 

that an eligibility application by an ERC provider is denied. 

And, for certain set-asides in the mass-based program, an 

affected EGU may believe that its generation numbers 

 

43 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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wereallowance 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. 

The actions we propose to list as appealable under the part 

78 procedures are as follows. 
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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 calculationallocation of generation by 

affected EGUs duringallowances from set-asides; decisions on the 

baseline period or compliance periodstransfer of allowances; 

decisions regarding the calculationfinalization of emissions

data by affected EGUs during compliance periods; decisions 

making error corrections to information submitted by affected 

EGUs and other account holders; decisions that there has been 

excess emissions requiring a 2-for-1 allowance administrative 
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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.

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 the 
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standards of performance establishedthat achieve the emission 

performance levels by determined by application of the Best 

System of Emission Reduction (BSER) in the Emission Guidelines 

(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 discussedthat is 

also available to states in the final CPP EG.EGs. The EPA has 

legal authority to establish either of the proposed trading 

systems as thea federal plan under CAA section 111(d)(2). We 

discuss this topic briefly here and invite public comment. The 

Emission GuidelinesEGs discussed the role of emissions trading 

in the BSER, see, e.g., &&& FR XXXX (XX XXXX) (“[section V]iewed 

from the source-category perspective, .A of the BSER implicitly 

includes an element of source-category-wide multi-unit 

compliance, which atpreamble to the level of implementation 

could be realized through trading of rate-based emission credits 

or mass-based emission allowances.”).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 Emission GuidelinesEGs 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. Id. Here we discuss why an emissions 

trading program is a lawful and appropriate form of federal 
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“implementation” of a "“standard of performance"” under CAA 

section 111(d)(2). We invite comment on this legal discussion 

and the agency’s 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).44

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 

sense, co-extensive with its authority to issue a federal 

implementation planFIP for National Ambient Air Quality 

Standards (NAAQS) pollutants under CAA section 110. This 

authority under CAA section 111, of course, must be understood 

 

44 The agency’s interpretation of the “remaining useful lives” provision is 

discussed above in section III.G of this preamble.
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in reference to the purpose of that section (i.e., to establish 

standards of performanceachieve emission reductions for 

designated pollutants from designated facilities), rather than 

in reference to the purpose of CAA 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 

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 federal 
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implementation plan (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 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 
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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 

section 110(c). The EPA believes this authority is the “same” in 

the sense described above and in the case law.45 The scope of the 

 

45 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, 
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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 RE 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 

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, 

 

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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the EPA would set emission standards for each of the affected 

EGUs in the federal-plan 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 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 
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does not, and needs not, propose an implementation approach of 

directly intervening to re-dispatch certain units, construct new 

RE 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 

Guidelines. [&&&cite XX FR XXXXX]. We adoptEGs. See section V.A 

of the same reasoning here, andfinal 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, 
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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 

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 
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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). See also 40 CFR 60.21(f) 

(defining an “emission standard” as “a legally enforceable 

regulation setting forth an allowable rate of emissions into the 

atmosphere, establishing an allowance system, or prescribing 

equipment specifications for control of air pollution 

emissions.”); 40 CFR 60.24(b)(1).

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 deferential 

standard of review 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 
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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 U.S. at 844).46

 

46 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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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 

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 
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and Budget, from the Office of the Assistant Attorney General 

(April 14, 1989) (hereinafter “OLC Memo”).47 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 ana 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 

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 

 

47 A copy of this memorandum has been placed in the docket for this 

rulemaking.
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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.

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 federal implementation plansFIPs 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.”48 This Strategy included as 

one of nine overarching implementation principles, “Marketbased: Use of market-based approaches and other innovative 

strategies to creatively solve environmental problems.” Further, 

 

48 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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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

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.49

As noted in the rulemaking notice for the final Emission 

Guidelines, &&&cite&&&,EGs, 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 

 

49 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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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 

finalized. New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008).50

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 carbon dioxide Emission GuidelinesClean 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.51

 

50 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.

51 We recognize that some commenters on the EGs raised concerns about the 

localized impacts that may occur from the potential for concentrations of copollutants 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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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 

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.”). 

Today’sThis 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
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The EPA’s federal plan requirements for GHGsCO2 from 

affected EGUs implement the EGs as previously discussed. In this 

federal plan and model rule proposal the EPA is proposing, as 

one 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 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 
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the EPA acting as the issuer of ERCs, and otherwise implementing 

and enforcing the standards of performance for affected EGUs 

subject to the federal plan.

This section describes how athe proposed rate-based federal 

plan and model trading rule and how each would be designed and 

operated, and how measures consistent with the CPP EGs building 

blocks can generate . For the federal plan, the EPA is proposing 

to limit the issuance of ERCs. to designated categories of 

affected EGUs and to RE resources and 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 EGs. The EPA requests comment on these 

means of generating ERCs and whether to limit the scope of the 

federal plan in this manner, and if not, what other sources of 

low- or zero-emitting electricity not included in the building 

blocksin federal plan states should also be eligible to generate 

ERCs for compliance purposes. AFor both the proposed federal 

plan and model rule, the EPA requests comment on which EM&V 

plan, measurement and verification (M&V) report, and 

verification report requirements should apply for each eligible 

resource. Further discussion of non-BSER measures that may be 

ableeligible to generate ERCs can be found in the CPP EGs. Clean 

Power Plan and section IV.C.3 of this preamble. (The EPA is not 

reopening its determination of the BSER.)
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B. Rate Goals

In the federal plan, the EPA is proposing to apply the 

subcategorized emission rates to the respective affected EGUs. 

The EPA is proposingClean Power Plan the EPA identified a ratebased federal plan that uses the “emissions standards” option 

from the EGs.

Rate Goals

In the CPP EGs the EPA established the “emission standards” 

approach as aan approvable method of compliance for state plans, 

while recognizing the availability of equivalent alternative 

methods of compliance. 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. As 

noted above, this proposed rate-based federal plan adopts the

“emission standards” approach. In the CPP EGs expressed as a 

rate of emissions of CO2 per unit of energy output. In the Clean 

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 gasfired stationary combustion turbines (i.e., natural gas combined 

cycle units, or NGCCsNGCC units) and fossil fuel fired steam 

generating unitsSGUs (i.e., utility boilers and IGCC units).)52.

 

52 For simplicity, affected utility boilers and IGCC units will collectively 

be called “steam generating units.”
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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 NGCCs, and utility boiler/IGCCNGCC

units, and SGUs, 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 

limitsstandards and the premises that these limitsstandards are 

based on are not within the scope of comment in this rulemaking

as they were finalized in the CPP EGsClean Power Plan.

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 subejctsubject to this proposed federal plan if 

finalized. The EPA is not opening for comment the 
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determinations, made in the CPP EGs,Clean Power Plan of each 

subcategorized CO2 emission performance rates. The emission rate 

standards for respective EGU types are provided for convenience 

in Table 46 of this preamble.

Table 4.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 

established in the final EGs. In Table 6of this preamble, the 

applicable standards for each interim compliance period is 

listed.

Table 6. 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 most closely correlatesprovides an 

incentive structure, as compared to how the EPA envisionsother 

rate-based approaches, that facilitates implementation of 

measures identified as part of the BSER to function. Using 

subcategorized rates allows for: (1) an equitable distribution 

of burden for consistently applied emission reductionsrates for 
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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 broadly 

solicits comments on all aspects of the subcategorized rate 

approach.The EPA solicits comments on whether the subcategorized 

rate approach is the preferred rate-based approach for the 

federal plan and model trading rule.53 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” implementation

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 

 

53 Note that the values of limits and determinations made as the BSER are not 

open for comment.
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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 proposalproposed federal plan, ERCs will be 

issued by the EPA to twothree categories of entities: (1)

Affected EGUs that perform at a rate below the applicable 

emission rate limit; and (2) RE providers that develop 

REstandard; (2) affected NGCC units for all generation 

(represents shifting generation from SGUs to NGCC units, as 

anticipated under Building Block 2); (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 and, taking comment on for the 

federal plan, and proposing for the model trading rule a 

potential thirdfourth category: other low- and zero-emitting 

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. .54

 

54 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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EGU Based ERC Generation

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 

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 difference of the limit the EGU is subject to minus the 

CO2 stack emission rate of the EGU subtracted from the standard 
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the EGU is subject to, and then this value is subsequently 

divided by the limitstandard 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 energyelectricity output from 

the EGU at that the EGU is applying the limit toemission rate.

This can be generically expressed as:

ERC MWhERCs

= (EGU limit − EGU operating rate)

EGU limit

(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, and,; conversely, a 

negative value indicates how many ERCs will need to 

surrenderedbe 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 

1,465500 lbs CO2/MWh. Assume it operates at 2,000 lbs CO2/MWh, 

and also assume it generates 1 million MWh over a compliance
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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 365,188333,334 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, 1,365,188333,334 MWh) equals the 

emission rate for compliance (1,465500 lbs/MWh). The needed 

quantity of ERCs for any given amount of generation can be 

easily calculated by dividing the total emissions of the 

affected EGU by the applicable emission rate limit, and then 

subtracting the generation of the affected EGU.

To incentivize The discussion in this subsection builds on 

and capture the emission reductions of Building Block 2applies 

the definition, benefits, use, and determination of using ERCs 

from the final EGs (section VIII of the CPP EGs, the EPA 

proposes in 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 NGCC generation hasstill fall 

within the capability to generate ERCs on a pro-rata basis 

reflecting incremental NGCC generation. established criteria 

described in the CPP EGs. Comments that solely relate to 
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determinations finalized in the EGs will be considered outside

the scope of this proposed rule.

2. Incremental NGCC operation is the relationship of an affected 

EGUs operation compared to the baseline year of 2012, used in 

setting the CO2 emission performance rates. Through ERCs

Building Block 2 there is a call to shift(BB2) of the BSER 

determination in the CPP EGs describes shifting generation from 

fossil steam EGUsSGUs to NGCCsNGCC units because NGCCsNGCC units

generate electricity at a lowerless carbon intensity and, thus, 

reduces CO2 emissions for the same intensive rate. BB2 describes

NGCC units generating at 75 percent of the unit’s annual 

operating capacity. This level of generation. To account for 

incremental generation the federal plan will use, for most NGCC 

units, would represent an increase in annual generation from a 

2012 baseline.For every hour of electricity generated by an NGCC 

beyond its 2012 baseline (i.e., incremental generation), there 

is a corresponding emission reduction in the power system.55 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 operation of a NGCC in Building Block 2 of 

75% to allow a NGCC to generate ERCs for operation in relation 

to the incremental NGCC generation detailed in Building Block 2. 

 

55 It is assumed that any increase in NGCC generation above 2012 levels is 

displacing fossil fuel-fired steam EGU generation.
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All 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 BB2Gas Shift ERCs (GS-ERCs) for clarity56. The 

collective sum of the BB2 GS-ERCs generated realizes the amount 

of emission reductions described in Building Block 2BB2 when 75 

percent capacity is achieved. This incentive is not a 

requirement, however. If NGCCsNGCC units do not collectively 

meet theincrease to 75 percent capacity, the missed emission 

reductions 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 

 

56 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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additional RE generation). The amount of BB2 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 

NGCCsNGCC units collectively will need towould generate to 

reachat the level described in Building Block 2BB2 (i.e.,

reaching 75 percent capacity).) and the associated emission 

reductions. This means that fractional BB2 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 summer time capacity factor

there will be thean amount of BB2 GS-ERCs equatingthat 

correlates to the emission reductions calculated in building 

block 2 anticipated under BB2 of the BSER. NGCCsNGCC units are 

expected to be incentivized to reach this level of generation 

because ofin part due to market demand for them. BB2 ERCs 

willGS-ERCs. Thus, GS-ERCs have the potential to play a largean 

important role in the sector meeting compliance obligations. 

The BB2 ERC generating factor is calculated by taking the 

number of additional MWhThe 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 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 SGU standard used as 
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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 region57 (i.e., the region with the 

highest calculated emission rate standard for 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 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 

capacity and dividing it by the the MWh that is 75 percent NGCC 

generation capacity, giving a factor. This factor is the rate at 

which BB2 ERCs are generated for every MWh of energy from an 

NGCC. This can also be expressed insummarized by the following 

equationexpression:

 

57 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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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).58 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 GSERC TSD. Table 7 of this preamble presents the proposed values 

that would apply for all NGCC units to calculate the amount of 

issued GS-ERCs.

Table 7. 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

BBBB2 EEEEEE GGGGGGGGGGGGGGGGGGGG FF FF FF = NN GGGGGG BBBB2 (MMMMh) − NN GGGGGG. 2012 (MMMMh)

NN GGGGGG BBBB2 (MMMMh)

 

58 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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The EPA has calculated this factor rate to be [&&&] 0.09 BB2 

ERCs/MWh. BB2 ERCs are generated at this rate by an NGCC for any 

level of annual generation to the grid. The calculation of BB2 

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. 

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 
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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 Clean Power Plan the 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 

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 
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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 

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 
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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 the 

NGCCits assigned emission standard for every MWh generated, but 

still be generating BB2 GS-ERCs. BB2 GS-ERCs may only be used to 

meet fossil steam generation units’ compliance obligations.

In the following example the EPA has taken the average NGCC 

operation in the Eastern Interconnect and divided it by the 75% 

of Building Block 2 to calculate an ERC generating factor for 

Building Block 2 of 0.09. This factor can be applied to every 

hour of operation of an NGCC to account for the effects of 

incremental operation of NGCC units across the system. The ERCs 

that are then generated can be used by any affected EGU that is 

subject to the sub-categorized steam EGU CO2 emission performance 

rate.

In thisAs 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 

780771 lbs CO2/MWh. Since the NGCC is always subject to its NGCC 
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emission rate limitstandard of 780771 lbs/MWh and it is 

operating at a rate above that limitstandard it will owe non GSERCs for all generationits own 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 llllll CC2 / [1,000,000 MMMMh + EEEEEE MMMMh] = 780 llllll CC2/MMMMh

850,000,000 lbs CO_2 / [1,000,000 MWh + ERC MWh] = 771 lbs CO_2/MWh

When that equation is solved for the number of ERC MWh 

needed, the NGCC would need to acquire 89,744102,464 ERCs to 

adjust its emission rate to its emission rate standard.

Additionally, the BB2 ERC generation rate, as determined by 

the [ref &&&] EPA, is 0.09 BB2 ERCs/MWh of NGCC generation. 

Using this value the quantity of BB2 ERCs generated can be GSERC Emission Factor for this NGCC is calculated by the following 

using 771 lbs CO2/MWh for the NGCC emission rate and 1,404 lbs 

CO2/MWh for the SGU emission standard in the equation: described 

above. 

NN GGGGGGGGGGGGGGGG GG ∗ BBBB2 EEEEEE GGGGGGGGGGGGGGGG GG = BBBB2 EEEEEE

And to solve the equation for this example:

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 
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the GS-ERC 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 GSERCs for this NGCC can be calculated. 

0.45 ∗ 0.26 ∗ 1,000,000 MMMMh ∗ 0.09

BBBB2 EEEEEE

MMMMh = BBBB2 EEEEEE = GS-ERC

The calculation results in 90117 thousand BB2 GS-ERCs being 

generated. Because an NGCC cannot use the BB2 GS-ERCs it 

generates to meet its compliance obligations, this NGCC will 

both generate ERCs (90117,000 BB2 ERCs for its incremental 

generationGS-ERCs) and owe ERCs (89,744102,464 non-BB2 GS-ERCs 

against NGCC limitstandard). This NGCC may sell (or otherwise 

transfer) or bank its BB2 GS-ERCs. If a BB2 GS-ERC is sold,

those proceeds may, in turn, be used to acquire non-BB2 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 SGU’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 thisthe proposed approach and 

requests comment and suggestions on other approaches for 

existing NGCCsNGCC units to generate GS-ERCs at all times. The
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EPA is considering this methodology that BB2 GS-ERCs are 

generated for all NGCC generation because it ensures that all 

existing NGCCsNGCC units are encouraged to run at a greater 

capacity. The EPA is requesting comment on alternative methods 

to account for NGCCs to generate BB2 NGCC units generating GSERCs. Specifically, the EPA solicits comment on NGCCsNGCC units

generating BB2 GS-ERCs once a threshold of electric generation 

for the year is achievedexceeded. This threshold is based on 

emissions from 2012 foras 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 ana unit level, if an NGCC generates 

more than it did in 2012, all generation above the 2012 level

(i.e, incremental generation) is eligible to be credited with 

BB2 GS-ERCs. The other threshold option is to use a percentage 

threshold. This percentage is the 2012 Evaluated on a regional 

NGCC generation of total NGCC regionallevel, the 2012 baseline

capacity in 2012. This percentage for NGCC units in the least 

stringent region is applied at theto all units. Each unit level 

and all generation by the NGCC thatis considered to be 

incrementally generating after it exceeds that percentthe

capacity at the NGCC is eligible topercent and will be credited 

with BB2 GS-ERCs accordingly. The BB2 GS-ERCs in these instances 

are calculated by the following equation: 
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BB2 ERCsGS-ERC

= (Steam standard − NGCC operating rate)

Steam standard

(Steam standard − NGCC emission rate)

Steam standard ∗ Incremental NGCC generation

This equation quantifies the reductions of the generation 

shift from fossil steam to NGCCsNGCC 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 BB2 GS-ERC generation is evaluated. An evaluation 

against each standard is independent of one another and BB2 GSERCs, in this situation, are only available for fossil steam 

compliance purposes.

While having a baseline threshold for EGU generation to 

credit BB2 GS-ERCs against closely resembles the EPA’s BSER 

determination, it enables a system in which BB2 GS-ERCs can be 

generated by displacingreplacing NGCC generation from one unit 

with other 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 BB2 GS-ERCs can be generated without necessarily 

corresponding to achieving the CO2 reductions anticipated by the 

BSER. Another aspect that reductions in CO2 emissions.
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The EPA considered is proposing to use a a pro-rata 

approach for generating BB2 also requests comment on whether a 

distinct type of ERC that comes with the proposed restrictions 

(i.e., GS-ERCs) is that this allows NGCCs to bid into the 

electricity market without having to adjust bids based on 

projecting whether or not the NGCC will generate beyond a 

threshold. 

This discussion builds on and applies the definition, 

benefits, use, and determination of using ERCs from the CPP EGs 

Section VIII. We invite comment on this approach as a 

methodnecessary to maintain the integrity of implementation of a 

federal plan and a model the rate-based trading ruleproposal.

Comments regarding this section that solely relate to 

determinations finalized in the EGs will be considered out 

ofoutside the scope of this proposed rule.

Other3. Eligible Emission Reduction Measures offor ERC 

Generation

Under the rate-based federal plan, the EPA is proposing to 

specify zero- and low-emittingemission reductions measures used 

to adjust an emission rate that are eligible for ERC issuance.

under the federal plan. Specifically, the EPA is proposing that 

RE capacity incremental to 2012 implementing the generation that 

meets the requirements for eligible resources in the EGs (as 

specified in section VIII.K of the final EGs), meets all other 
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requirements related to ERC issuance in the EGs and this 

proposal, and falls into one of the following specific 

categories of RE measure typesresources (as specified in section 

V.E of the final EGs) are eligible for rate-based crediting: onshoreto be issued ERCs: wind, solar photovoltaics (PV), 

concentrated solar power, geothermal power, and hydropower.59

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 EGs (as 

specified in section VIII.K of the final EGs) and all other 

requirements related to ERC issuance in the EGs and this 

proposal are eligible to generate ERCs. Further, these RE and 

nuclear measures must have the capacityability to provide data 

from a revenue quality meter, a requirement whichthat is further 

discussed in Sec.section IV.G.4 Evaluation, Measurement, and 

Verification, provided below. This treatment for eligible 

measure types is also proposed for the set-aside for RE that is 

part of the proposed mass-based implementation approach, and all 

proposed aspects of the eligible measure types described in this 

 

59 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 setaside 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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section and the requests for comment included below also apply 

in the mass-based set-aside context. The set-aside method and 

the use of this eligibility treatment within it are specified in 

Sec. &&&.D.8 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 EM&V implementation under a federal plan, 

asbecause they can use their existing metering infrastructure to

quantify generation and submit it for ERC issuance. This EM&V 

approach is allowable under the EM&V requirements in this 

proposal, outlined in Sec. &&&, and is consistent with the 

requirements outlined in the final guidelines (see Sec. 

VIII.&&&).A concern unique to federal plan implementation is the 
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need for an ERC issuance 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 zeroand low- emittingemission reduction measures as eligible for ERC 

issuance under the rate-based federal plan, and comments on how 

to assure suggested sources can be validated to assure 

reductions of CO2. 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 various treatment options for different types of 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 
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appliance standards, and conservation voltage reduction. The 

agency also requests comment on the inclusion of combined heat 

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 zero- or lowemitting measure typesemission 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 
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EGs, such as the requirement that the measure be incremental to

2012.

The EPA acknowledges that as new technologies mature, there 

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 
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of biomass and an option for the treatment of biomass in both 

the proposed rate-based federal plan and proposed rate-based 

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 or reducing the contribution of

CO2 emissions to the atmosphere (see Sec. &&&).increases of CO2

levels in the atmosphere (see 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 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 wastederived feedstocks via mandatory and voluntary programs 

supporting such efforts.60 Some states have also acknowledged the 

 

60 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 
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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.61

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 

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 

 

fraction of MSW at waste-to-energy facilities (as discussed in section 

VIII.I.2.C of the final EGs).

61 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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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.62The EPA is engaging in a second round of 

targeted peer review on the revised Framework with the SAB in 

2015.63 Information in the revised Framework and the second SAB 

peer review process, including stakeholder comments, will assist 

the EPA in assessing potential qualifyingqualified biomass 

feedstocks in federal plan applications. 

Provided for comment below are optionsIf 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 massbased plan allowance set-aside and to the calculation of covered 

emissions for affected EGUs that are co-firing biomass, which 

include:.

 

62Specifically, 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/biogenic-emissions.html.

63 http://www.epa.gov/sab. 
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• A list of specific acceptable biomass fuels 

• General principles and/or specific criteria regarding biomass 

fuel production, processing and use for energy

• A combination of the above options. 

The firstThis option offered for comment is to specify a 

list of specific pre-approved acceptablequalified biomass fuels. 

For example, the EPA could recognize the biogenic CO2 emissions

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), based on). 

As another example, the EPA could also recognize biomass 

feedstocks from sustainably managed forests lands, provided that 

these feedstocks meet certain requirements such as demonstration 

that the conclusions supported by a variety of technical 

studies. Thefeedstock 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 as the science 

related to biogenic CO2 emissions assessments evolves. Also,The 

EPA asks for comment on whether to include a provision could be 

included that allows sources to seek approval for other types of 
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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 second option offered for comment would be to establish 

general principles and/or specific criteria concerning the 

production, processing and use of biomass fuels. These 

principles or criteria would reflect sustainability and 

sustainable practices that enhance carbon sequestration and

storage in a manner consistent with widely accepted principles. 

For example, general principles for forest- and agriculturederived biomass fuels could include efforts to: protect, 

sustain, and enhance ecosystem health and vitality; maintain and 

enhance carbon sequestration and storage; ensure long term 

forest and landscape productivity and economic viability; 

protect culturally and environmentally sensitive areas; and 

employ rigorous monitoring and verification of carbon stock 

levels.

Under this option, the EPA could specify criteria for the 

production, processing and use of forest- and agriculturederived biomass fuels that could also include the preservation 

of, and/or limiting or restricting the use of biomass fuels 

from, natural and old growth forests, peatlands, wetlands, high 

conservation value areas, biodiverse areas, protected lands and 
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other sensitive lands.

Examples of other potential criteria include:

• Improved management to increase carbon sequestration 

benefits and protect forest health, including the retention 

of recommended levels of slash, woody debris, crop and 

other biogenic materials from harvest/related activities.

• Limitations on deforestation and targeted land use change, 

especially of high carbon and/or otherwise ecologically 

sensitive areas for the production of bioenergy feedstocks.

• Employment of sustainable management practices which 

promote production levels that can continue at a given 

intensity of management consistent with required 

environmental protection and which is professionally 

planned to achieve over time the desired balance between 

growth and removals on the landscape.

• Maintain soil and water quality and minimizing the amount 

of fertilizers and chemicals used on biomass fuel-producing 

lands through integrated pest and fuel management 

activities. 

• Use of the best scientific information and systems 

available to assess landscape health, carbon stock 

attributes and net carbon emissions attributable to 

production harvesting and use of biomass for combustion, 
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and to continually refine and update inventories of these 

attributes. 

• Monitor and verify implementation of sustainable production 

and best management practices, including credible records 

and other evidence of management, monitoring and 

verification activities. 

• Ensure forest and landscape productivity, and economic 

viability, including primary and secondary products. For 

example, if the biomass fuel is an industrial process 

residuals64, then the primary uses of sourced material (i.e. 

non-energy products) and related land use and industry 

practices remain intact. 

The third option offered for comment is a combination of 

the specific acceptable feedstock list and, for feedstocks not 

included on that list, general and/or specific criteria that 

reflect sustainability and sustainable practices considered in a 

manner consistent with widely accepted principles.

The EPA also requests comment on options for demonstrating 

compliance with the options listed above that include criteria 

that reflect sustainability and sustainable how EGUs would 

demonstrate that feedstocks meet the requirements to be accepted 

 

64 Industrial process residuals can be considered as substances that are not 

the primary end product that a production process is in place specifically to 

produce. Residual materials are not a primary aim of the production process 

and the process has not been deliberately modified to produce it.
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as a pre-approved qualified biomass feedstocks. These 

requirements could include demonstration of certification or 

verification of practices that are additional to the other 

monitoring, reporting and EM&V requirements discussed in section 

&&& above. These options for demonstration of compliance with 

criteria are described below. 

The first option offered for comment would require this 

proposal, such as provision of sufficient credible evidence, 

such as monitoring records and metrics showing that the 

forest/agricultural feedstock sources meet the criteria listed 

above and any others that might be adopted, and are at low risk 

of non-compliance. 

The second option offered for comment would require the 

provision of approvedanalysis of carbon benefits, third party 

verification and/or certification entities or programs to 

demonstrate compliance with established sustainability criteria. 

Biomass that is acknowledged as sustainable and certified under 

a verification body and/or third party scheme [(e.g., Forest 

Stewardship Council, Programme for the Endorsement of Forest 

Certification, Sustainable Forest Initiative], that is deemed or 

determined to be acceptable is at low risk of non-compliance 

with the criteria offered for comment. These third party 

verifications can include demonstration of sustainable origin of 

feedstock (via chain of custody verification), mass balance 
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calculations and/or other performance-based metrics. The EPA 

requests comment on what considerations, if any, to take into 

account when including acceptable certification programs or 

criteria. The third option offered for comment allows for the 

use of any other verification programs or entities to 

demonstrate compliance which are not pre-approved but can be

proven to employ generally accepted sustainability metrics. For 

example, this would include verification programs that reflect 

sustainable production practices and responsible land use 

resource management, are performance based, and are at low risk 

of non-compliance may be used. Entities that use verification 

programs that are not pre-approved may be required to provide 

additional forms of records and metrics to verify feedstock 

sustainability.

The fourth option offered for comment requires , or a 

determination of the biogenic emissions and sequestration 

related to the production, processing and use of the biomass 

fuel, with supporting records. A potential calculation method is 

the application of an assessment framework like that provided in 

the 2014 Framework for Assessing Biogenic Carbon Dioxide for 

Stationary Sources that assesses the extent to which the 

production, processing, and use of biogenic material results in 

a net atmospheric contribution of net biogenic CO2 emissions. 

This type of method could use the actual measured (and verified) 
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net biogenic CO2 emissions and sequestration values or biomass 

fuel-specific default values to calculate the carbon intensity 

of the biomass fueleffects related to the production, processing 

and use of the feedstock. 

It is possible that compliance options could be implemented 

in isolation or simultaneously (e.g., use of certification 

and/or verification entities and determination of biogenic 

emissions). 

The calculated carbon intensity of the biomass feedstock 

could then be applied to calculations relevant to meeting ratebased and mass-based obligations through co-firing of biomass.

The EPA is taking comment on the following options. The carbon 

intensity of the feedstock in question could be used to 

determine the net emissions of biomass used as a co-fired fuel 

at an affected EGU. As is outlined in the final EGs (see Sec. 

&&&), an affected EGU using qualifying biomass as a fuel must 

monitor and report both its overall CO2 emissions and its 

biogenic CO2 emissions. In a rate-based context, the biogenic 

emissions can be included in the calculation of the fossil rate 

at the affected EGU for the purpose of determining whether the 

affected EGU has met its obligation under a rate-based federal 

plan. In a mass-based context, the affected EGUs that are cofiring would be required to hold allowance equivalent to those 

calculated biogenic emissions. 
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The EPA requests broad comment on the types of qualified

biomass feedstocks that should be specified in the final model 

rule, if any. We request 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 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 request

comment on any other requirements that should be included in the 

final model rule regarding EM&V for qualified biomass. 

Discussion of the biomass EM&V requirements in the rate-based 

model rule can be found in 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 Emission Guidelines preamble section VIII.G.1.b: 

Actions takenK.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. Our intent is 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 
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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 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 units65 may be used to adjust the CO2

emission rate of an affected EGU). , as CHP units are lowemitting electric generating resources that can replace 

generation from affected EGUs. Electrical generation from nonaffected 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.

 

65 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.66 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:

 

66 The applicable CO2 emission rate standard is in Table 6. of this preamble.
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CHP electrical CO2 emission rate = [CHP fuel input67 * fuel 

emission factor68 – (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 non-affected CHP unit would have occurred 

anyway from an industrial boiler used to meet the thermal load 

in the absence of the CHP 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 

 

67 This term generally represents the thermal energy associated with the total 

fuel input.

68 The fuel emission factor can be determined through 40 CFR Part 75 Appendix 

G. 
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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.69 There are also WHP facilities where the 

waste heat from the initial combustion process is used to 

generate 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 

 

69 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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associated with that additional power generation. As a result, 

the incremental electric generation output from the WHP 

facilities could be considered non-emitting, 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.70 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.71In 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 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

 

70 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.

71 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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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 part of, 

including affected EGUs that are under a ready-for-interstatetrading ready 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 

limitsstandards. The ATCS would also provide data to the ERCs 

market and the public, including a 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 
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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 iswould be implemented and 

administered are detailed. This section elabrorates on this 

proposal, which implements through specific provisions the 

requirements for rate-based trading programs in the EGs. 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 

commentscomment on means to expedite the process of issuing 

ERCs, any minimum and means to insure the integrity of 

themaximum periods for which ERCs that mayshould be issued

(e.g., monthly, quarterly, annually), and any means to ensure 

that the ERCs issued meet the requirements of the EGs 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. 

1. Designated Representatives and Alternate Designated 

Representatives 

This section establishes the procedures for certifying and 

authorizing the designated representative, and alternate 
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designated representative, of the owners and operators of the 

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 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 

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 
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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

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 
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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 

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 BB2a 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 
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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 areused only once 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,72 and an accompanying tracking system infrastructure 

design. Each issued ERC will have a unique identifier (i.e.,

 

72 “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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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 on the Clean 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 Clean 

Power Plan.

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.
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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 

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 
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designated representatives and alternates. The EPA requests 

comment on these compliance mechanisms. 

Averaging

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 

by taking the total measured CO2 mass in units of pounds of CO2

emitted(lbs) summed over the compliance period for an affected 

EGU and dividing it by the total net MWh of energy output over 

the compliance period for that affected EGU produced.in units of 

MWh.73 This averaged emission rate will be compared to the 

emissions standards that the EGU is subject to during the 

corresponding interimcompliance period or final goal..

Accordingly, and if necessary, the appropriate number of ERCs 

 

73 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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will be deductedretired 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 3-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) 

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 regarding
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issuance of ERC intervals.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 rate74, the EPA will issue 

those ERCs into the affected EGU’s compliance account in ATCS. 

The issuance will occur annually 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 RE, Demand-Side EE and Other 

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 RE and other measures 

used to adjust an emission rate that seeks to 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 

 

74 As described in section IV.C.1 of this preamble.
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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 RE 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 a project to the EPA an 

eligibility application for EPA approval to EPA, 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 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 

projecteligibility application, as specified for these measures 

in the final EGs:
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(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 areis only being credited in the federal 

frameworkplan, and will not be submitted for ERC 

issuance in any other rate-based crediting system in 

any other state. As discussed in section &&& above, it 

is proposedIV.C. of 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 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 Sec. &&§ion IV.C of 

this rulepreamble.

(3) The provider must show that the project has an 

EM&V protocolplan that meets the federal plan 

requirements. Proposed requirements specific to the 

federal plan are proposed in Sec. &&§ion IV.D.6 of 

this rulepreamble. As specified in section IV.D.8 of 

this preamble, we request comment on whether nuclear 

energy resources should be subject to the same EM&V 

requirements as RE 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 stateplan. For 

eligible RE capacity, the provider can only be 

credited in a rate-based state or rate-based multistate 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 can make this 

demonstration by providing documentation of a power 

purchase agreement (PPA) or delivery contract from the 

rate-based state.or delivery contract from the ratebased 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 
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inclusion is further discussed in section III.A of 

this preamble on Interstate Effects and also discussed 

in the Interstate Effects section of the final 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. This 

requirement and the justification for its inclusion is 

further discussed in Sec.&&& on Interstate Effects and 

also discussed in the Interstate Effects section of 

the final guidelines (Sec. VIII.G.2). and incremental 

nuclear generation under the federal plan. 

(5) This application must include an independent 

third-party 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 

belowin section IV.D.6 of this preamble. 

We request comment on each criterion of the 

eligibility application described herein 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.

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 administering the rule that providesthe ERC issuance 

process. It will provide for transparent access to RE project 

and program eligibility applications and regulatory approvals as 

well as information on ERC transfers andthe activities of 

accredited third party verifiers (third party verifiers are 

further discussed belowin section IV.D.6 of this preamble), as 

part of Evaluation, Measurement and Verification).well for the 

public to be able to generate reports based on this information.
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The agency is proposing that thesethe 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 a periodican annual basis. 

The agency requests comment on whether a quarterly or semiannualbiannual application process is more appropriate. These 

applications will be accepted through the entirety of all 

compliance 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 RE providers submit an 

application for ERC issuance 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 

creditERC 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. This needs to meet 

the federal plan EM&V requirements outlined in Sec. 

&&&.
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(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. This can be shown through a finding 

from a third-party verifier that meets federal plan 

requirements.

(3) Documentation that the MWh resulted from RE or 

incremental nuclear capacity eligible for crediting 

under the federal plan requirements and in accordance 

with final EGs. This documentation should note if the 

MWh are from an RE project located in a state with a 

mass-based stateplan, and show if the generation is

approved to be eligible for ERC issuance under the 

federal plan. See section III.A.2IV.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 

all components of the application.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 EPA or its designated agent, ERCs will be issued to 

the provider by EPA through the federal plan credit tracking 

systemthe 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 the proponent 
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to register for a general account in the EPA tracking system 

where the ERCs would be recorded. See 40 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 

40 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 40 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 EGs 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 overand under-statements, to material inconsistency with rule 

provisions, to fraud, etc.). In addition, the federal plan and 

model rule include provisions that provide that, at any time for 

cause, the EPA may temporarily or permanently revoke the 

qualification status of eligible resources (from being issued 
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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 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 issuanceeligibility

applications will be accepted afterstarting before the 

beginning of the first compliance period, as soon as the 

agency is able to establish (January 1, 2022), through an 

application process, and the agency will establish and 

administer (unless delegated or taken over through a partial 

state plan), and that applications will be accepted on a 

periodican annual basis, either quarterly or semi-annually..
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These applications will be accepted through the entirety of 

all compliance periods. The EPA will review and approve 

eligibility applicationapplications, and may designate an 

agent to coordinate and assist with credit issuanceERC 

eligibility applications. The EPA is proposing that ERC

issuanceit will issue ERCs for each compliancea given year 

will be available a maximum ofno later than 6 months after the 

end of the relevant year, to allow for . This amount of time 

may be necessary EM&V documentation.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 

performance period.

The EPA proposes that certain pre-compliance measures are 

eligible for crediting reductions during compliance, in 

accordance with what is allowable under the final emissions 

guidelines (Sec. &&&). Specifically, RE capacity installed after 

2012 is eligible for ERC issuance for all of its generation 

during the performance periods 2022-2030. This corresponds with 

treatment in the final emission guidelines, and ensures access 

to the RE generation assumed in CO2 emission performance rates 

and goals. period.

Additionally, affected EGUs in jurisdictions subject to 

the federal plan will be able to use rate-based ERCs or mass-
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based allowances available from the clean energy investment 

pool, which rewards early action on implementing RE and 

demand-side EE. The clean energy investment pool is specified 

in the final guidelines (see Sec.&&&). 

For purposes of the proposed rate-based federal plan, the 

EPA proposes to implement the Clean Energy Incentive Program 

(CEIP) on behalf of a state by issuing early action ERCs for 

eligible actions located in or benefitting that state that are 

implemented after September 6, 2018 and that generate zeroemitting MWh or reduce energy demand in 2020 and/or 2021.75 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 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.

 

75 As discussed in section VIII.B.2 of the final emission 

guidelines, in the case of a state that submits a final state 

plan including requirements for the state’s participation in the 

CEIP, eligible RE projects may commence construction, and 

eligible EE projects may commence implementation, following the 

date of submission of a final state plan to the EPA. These 

projects must be implemented in or benefit the state that 

submitted the final state plan to the EPA, and may receive 

incentives for the zero-emitting MWh they generate or the enduse energy savings they achieve during 2020 and/or 2021.
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• 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 

RE porjects that commence construction and eligeible EE projects 

that commence implementation after September 6, 2018 and that 

generate zero-emitting MWh or reduce end-use energy demand 

during 2020 and/or 2021. These projects must be located in or 

benefit the state on whose behalf the EPA is implementing the 

federal plan. 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 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 
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the same stringency, taking into account the additional borrowed 

ERCs. The EPA requests comments on all potential methods to 

adjust state targets, including modeling-based 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 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 
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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 be 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 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 poolthat the 

state is eligible to receive. Any matching ERCs that remain 
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undistributed after September 6, 2018 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.

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.
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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 

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.76

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 

 

76 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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verifcation services related to the Clean Power Plan. Accredited 

verifiers must be independent. Accredited verifiers may not 

provide verification services for any eligible resource for 

which they have a financial, management, or other interest.77

Such relationships constitute a conflict of interest (COI). COI 

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 

 

77 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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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.78 The EPA 

requests comment on the proposed necessary requirements for an 

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.

 

78 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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8. Evaluation, Measurement, and Verification (EM&V) Plans, 

Monitoring and Verification (M&V) Reports, and Verification 

Reports

The EPA is proposing that issuance of ERCs to credit 

eligible measures requires the implementation and documentation 

of sufficient EM&V79. Such EM&V requirements, which reflect and 

are generally consistent with prevailing industry-standard 

practices, are specified in the final emissions guidelines (see 

Sec. VII.&&&). The EPA is proposing that the EM&V required for 

issuance of ERCs under the federal plan meet the requirements 

specified in the final guidelines, with the following additional 

proposed requirements and specification of final emission 

guideline requirements.

Section VIII.G.5.f of the final guidelines provides 

specific requirements for the provision of RE data as part of an 

EM&V demonstration, and all those requirements will need to be 

satisfied under a federal plan. The following proposed federal 

plan requirements are drawn from that section. Proposed eligible 

measures for ERC issuance must all have the capacity to provide 

 

79 EM&V is defined here as the set of procedures, methods, and 

analytic approaches used to quantify the MWh from RE and demandside EE, 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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data from 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. These 

data can then be submitted to the federal plan tracking system.

In this proposal we are requesting 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.80

Only a subset of the potentially creditable ERC resources 

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, geothermal power, hydropower, new nuclear units and 

capacity uprates at existing nuclear units, and 2) they can 

 

80 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 demandside EE and any other measures that could be eligible. 
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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 and, demand-side EE measures, and any other measures 

that may be eligible under the final guidelines as eligible 

measures under the federal rule. EM&V requirements for such 

measures are specified in detail in the final guidelines 

preamble Sec. VIII.G.5.plan. For commentersstakeholders that are 

submitting comments on the inclusion of such additional 

measures, the EPA requests commentscomment on how the EPA could 

implement across applicable jurisdictions a rigorous, 

straightforward, and widely demonstrated EM&V methodology set of 

EM&V methods, procedures, and approaches that could be 

implemented in the time frame allowed by the federal plan and 

that also meetsmeet 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 proposed model 

trading rule for states to use.state plan. Thus, commenters on 

this aspect of the proposal should consider whether and how 

these provisions could be implemented at the state level. The 

EGs set minimum requirements for rate-based programs, including 
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ERC EM&V. Thus commentsComments that suggest an approach not 

authorized by the EGs maywill 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 that extent.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.81

The final EGs provide requirements for independent 

verifiers, including standards for accreditation and eliminating 

conflict of interest (see Sec. VIII.&&&). The EPA request 

comment on the specific requirements that third party verifiers 

should meet prior to participating in the federal plan ERC 

issuance process.

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 

 

81 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 that can be approved for use, provided 

that such approaches are functionally equivalent to the provisions for EM&V 

outlined in this section. 
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compliance with the EGs. 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.82

a. Overall Approach and Measure-Specific Requirements. The 

proposed Clean 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 Clean Power Plan proposal and 

associated “State Plans Considerations” TSD83 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 demand-side 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 

 

82 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.

83 See discussion beginning on p. 34 of the State Plan Considerations TSD for 

the Clean Power Plan Proposed Rule: http://www2.epa.gov/carbon-pollutionstandards/clean-power-plan-proposed-rule-state-plan-considerations.
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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 

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. 

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.3.b of the final 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, 
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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 

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 
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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 

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 
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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 

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 
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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 

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 
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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 quantification of RE generation 

can leverage the infrastructure and documentation associated 

with the establishment of renewable energy certificates (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, 
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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 Kilowatt 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, 

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. 
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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 Kilowatt, 

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 
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type of RE resource (including the relvant size and distribution 

of such resource) that qualifies for issuance of ERCs for use in 

Clean Power Plan compliance.

For RE resources with a nameplate capacity of 10 Kilowatt

or more and for RE resources with a nameplate capacity of less 

than 10 Kilowatt 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 10 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 RE 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 
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from a group of wind turbines be aggregated with generation from 

a group of solar panels? We seek comment on the appropriate 

thresholds for the aggregated of individual units (e.g., 

nameplate capacity of less than 150 Kilowatt 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 Kilowatt, 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 RE 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 10 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 nuclear 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 RE resources, and if not, we take comment 

on to which EM&V requirements nuclear energy resources should be 

subject.
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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 Kilowatt, and how to account for T&D 

losses. 

In order to determine the incremental CO2 emission rate, a 

CHP unit would monitor requirements for CO2 emissions and energy 

output.84 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 facilities85 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 

CHP facilities with electric generating capacity less than or 

equal to 25 MW, which use only natural gas and/or distillate 

 

84 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.

85 A CHP facility may consist of one or more electric generators.
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fuel oil, the low mass emission unit CO2 emission monitoring and 

reporting methodology outlined in 40 CFR part 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 RE 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 CHP 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. We also take comment on 

specifying in the final model rule that if a CHP 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 

part 75. We take comment on any alternatives to these 

measurement methodologies that should be specified in the final 

model rule. We take comment on any other requirements that 

should be included in the final model rule regarding EM&V of 

CHP. 
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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 

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 
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regarding EM&V for qualified biomass. Detailed discussion on the 

role of qualified biomass feedstocks can be found in 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-to-energy 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 EGs (see section VIII.K.1 of the 

final EGs), only the portion of electric generation at a wasteto-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 
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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 RE resources, and we take 

comment on any additional EM&V requirements to which waste-toenergy 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 proposes EM&V provisions that will be presumptively 

approvable if included in state regulations governing how EE is 

to be quantified by EE providers and verified by independent 

entities acting on behalf of the state. As 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 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 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 measure. 

(1) Common Practice Baseline.
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Based on public input and assessments of industry bestpractice protocols and procedures, the EPA is proposing that it 

is presumptively approvable to quantify EE savings 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 

what would commonly have happened in the absence of the EE 

program, project, or measure. 

The applicable CPB depends on a number of factors, such as 

characteristics of the EE program, project, or measure, the 

mechanism by 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 circumstances, which may be presumptively approvable, 

can be found in the EPA’s EM&V guidance. EE providers must 

document the selected CPB in their EM&V plans, along with clear 
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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 proposes criteria that are presumptively 

approvable 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. 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 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 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 
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recurring basis over the effective useful life of the EE project 

or measure in order to ensure accurate and reliable savings 

values. To be presumptivey approable, the EPA is proposing that

EE providers must apply the above methods at a minimum of 4-year 

intervals for building energy codes and product standards; every 

1, 2, or 3 years for publicly- or utility-administered EE 

programs, depending on the program type, magnitude of savings, 

and 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. The 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. Where feasible, the EPA is 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.
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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 if those values (a) are

documented in a publicly available database (also known as a 

Technical Reference Manual) that is accessible on a public Web

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) are updated at a minimum of 

every 3 years to reflect the per-measure MWh savings documented 

in ex-post EM&V studies apply M&V or comparison group methods. 

For M&V methods to be presumptively approvable, the EPA is 

proposing is that industry best-practice protocols and/or 

guidelines must be followed. Examples of acceptable bestpractice protocols and guidelines are provided in the EPA's EM&V 

guidance. EE providers can consult the EM&V guidance to assess 

the applicability of these technical resources to the EE 

programs and projects generating savings, and must document how 

one or more best-practice protocols or guidelines will be 

appropriately applied in EM&V plans (along with clear 

documentation and discussion of the rationale, applicability, 

and relevant data sources, and other supporting information). 
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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 provisions: 

• How major changes in independent variable conditions 

(weather, occupancy, production rates, etc.) that affect 

energy consumption and savings estimates will be 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 utility consumer-funded 

EE programs and project-based EE are evaluated site-bysite). 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 best-practice techniques (e.g., phone or mail 

surveys, document review, site inspections, spot or shortterm 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 losses86 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 

 

86 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).
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and volt/VAR optimization87) may adjust reported savings by 

using a T&D adder. If such an adder is applied, the

presumptively approvable approach 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. EIA State 

Electricity Profile.88

• How the duration of EE program or project electricity 

savings will be determined. This must be determined using 

industry best-practice protocols and procedures involving

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 rigor89 of the 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.

 

87 More information about these technologies is in section VIII.F.1 of the 

final EGs.

88 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.

89 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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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. In particular, the EPA is proposing that, to be

presumptively approvable, EM&V plans must 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. EM&V reports must 

include documentation of how such 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 EGs rulemaking process in allowing states to issue ERCs for 

quantified and verified MWh savings from DS-EE under state 

plans. Consistent with these perspectives, the EPA is proposing 

that any demand-side EE program, project, or measure that 

results in MWh savings may be potentially eligible to generate 

ERCs, including under this proposed model trading rule, provided 

that they meet the presumptively approvable provisions for 
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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 EGs and 

the state plan. Examples of potentially eligible demand-side EE 

program and project types include: 

• Publicly or utility-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 

requirements of the EGs. 

(6) Requests for Comment on Energy Efficiency EM&V.
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We take broad comment on each EE EM&V criterion 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 released 

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 

program, project, or measure. We take broad comment on what 

constitute EE best-practice protocols and procedures for every 

type of EE program, project, or measure.
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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 

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.
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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 

today, and we would expect them to leverage 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 

EGs. The EPA takes comment on what criteria it should include in 

the final model rule, and what level of details with respect to 
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those criteria that it should include, in order to ensure that 

an ERC issued for an EE program, project, or measure in one 

state reflects the same 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 

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 
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EM&V plan. In particular, we take comment on the circumstances 

and conditions in which double counting is most likely to occur 

(including 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 estimates, including the necessary rigor of the methods

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 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 quantify the transmission and distribution loss 

based on the lesser of 6 percent of the site-level electricity 

comsumption 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 
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published in the U.S. EIA State Electricity Profile. We take 

comment on the appropriateness of including 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 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 
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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 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 

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, 
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although the affected EGUs that are regulated under the ratebased federal plan would use ERCs as a compliance instrument, 

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 75.90 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 

 

90 See section IV.D.11 of this preamble for more information.
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delineated in section IV.F.4D.8 of this preamble. Because of the 

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.91

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 

 

91 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 deadline92 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 

energy with zero CO2 emissions deemed associated with it for the 

 

92 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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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. This account 

available for the public to view. The EPA promotes transparency 

throughout the entire process. 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. 

AAAAAAAA AA EEEE = MM oo CC2 (llllll)

GGGGGGGGGGGGGGGG GG (MMMMh) + MMMMh EEEEEE

Adjusted Emission Rate = Mass of CO2 emitted (lbs)

Generation (MWh) + MWh ERCs

This equation can be rearranged to:

MMMMh EEEEEE = MM oo CC2 (llllll)

AAAAAAAA AA EEEE ( llllll

MMMMh)

− GGGGGGGGGGGGGGGG GG (MMMMh)

MWh ERCs = ass of CO2 emitted (lbs)

Adjusted Emission Rate ( lbs

MWh)

− Generation (MWh)

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 
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an ongoing obligation until compliance is achieved, and there is 

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 allowingproposing 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 

concept that an affected EGU may use an ERC that the EGU will 
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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 ERCemission 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 Part40 CFR 75.60. The use of 40 CFR part 75 certified 

monitoring methodologies would be required. Many affected 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 
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under 40 CFR 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 Mercury and Air Toxics 

Standards (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 accordance with 40 CFR part 75. RGGI and ARP 

currently require the reporting of CO2 mass emissions on an 
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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 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 allowancesan 

enforceable emission standard would commence on the compliance 

period schedule that is detailed in section IV.III.D of this 

preamble.

E. 3.

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 

“presumptively approvableready-for-interstate-trading” plans in 

the EGs that affected EGUs located in states with approved

ready-for-interstate-trading state plans using the subcategorized 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 presumptively approvableready-for-interstate-trading

state plans will be able to trade ERCs seamlessly across 

jurisdictional borders because of the assurances of being 

presumptively approvable. Presumptively approvableReady-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 presumptively approvableready-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 
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means of 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 presumptively approvable.ready-for-interstate-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 program. 
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The EPA requests comment on a broader approach that would 

allow all affected EGUs that are located in states with approved 

rate-based state plans to participate in the federal plan 

trading program. In other words, this would extend federal-plan 

linkage to rate-based programs that are not set up to be 

“presumptively approvable,” or which use a set of emission rates 

for affected EGUs that are different from the national uniform 

subcategorized rates. We request comment specifically on what 

conditions or requirements would be needed in these cases in 

order to participate in the federal plan trading program in a 

way that is administratively feasible and maintains the 

integrity of all of the linked programs. Although the agency has 

serious concerns about the administrative complexity of this 

approach, we also request comment on the feasibility and 

potential mechanism of allowing EGUs in states with approved 

mass-based state plans to participate in a federal rate-based 

trading plan. 

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 conclustionconclusion 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 
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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 

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.
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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 metricshort tons of emissions. The 

EPA is proposing that allowances be issued in metricshort tons

for the federal plan, and also requesting comment on the 

issuance of allowances in short tons.

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 

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 
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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 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 federally-
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administered 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 

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 

metricshort 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 twothree

types of allowance set-asides, is discussed in section V.D., of 

this preamble, below.
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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. of this preamble. In the proposed massbased 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 
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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 

the agency would identify qualifying biomass and provide a 

methodology for the treatment of biomass (i.e., to assign zero 

or partial emissions to 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 after reflectingless the zero or partial emissions 

attributed to the co-fired qualified biomass; such an approach 
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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 three3-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 

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.
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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

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
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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

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

(metric tons)

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 

burden, compared to a single-year compliance period. The EPA 

seeks to strike a reasonable balance between providing 
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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 (The 

RGGI) uses three3-year compliance periods, along with 

interimintervening compliance periodsrequirements. The RGGI 

interimintervening compliance period is a requirement foris that

sources tomust hold allowances to cover 50 percent of emissions 

for the first two calendar years of each three3-year compliance 
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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 interim 

periodintervening requirement are subtracted from the three3-

year obligation.93 The California Air Resources Board (CARB) Capand-Trade Program also uses three3-year compliance periods, 

along with interimintervening compliance periodsrequirements.

The CARB interim compliance period evaluatesintervening 

requirement is to evaluate compliance on 30 percent of each 

source’s previous year’s emissions every year, and 

evaluatesevaluate compliance for the remainder of emissions

every three3 years.94 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 

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

 

93 RGGI, Summary of RGGI Model Rule changes: February 2013. 

http://www.rggi.org/docs/ProgramReview/_FinalProgramReviewMaterials/Model_Rul

e_Summary.pdf Accessed June 9, 2015.

94Overview 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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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 

“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 
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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 

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 
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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 

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 mass-
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based 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 NovemberMay 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 deadline95 for that

first compliance period (after which point the EPA would 

evaluate compliance) would be on NovemberMay 1, 2025. The agency 

also requests comment on an earlier or later allowance transfer 

deadline, such as June 1 or March 1, of the year after the last 

year in the compliance period. 

 

95 The “allowance 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. For further information see section V.G of 

this preamble.
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The EPA proposes to evaluate compliance (i.e., allowance 

true-up) at the facility level, not at the individual 

unitaffected-EGU level., in the mass-based trading program.

Facility-level compliance easesmay 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 makesmay make it easier for 

the designated representatives to manage their allowances. This 

also eliminates the potential for a facility that held 

sufficient allowances to mistakenly hold them in the wrong unitlevel compliance accounts, which puts the unit out of 

compliance. 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.

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 
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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, 

approachapproaches to distribute allowances.

The initial allowance allocation approach that is based on 

historical data does not affect the environmental results of the 

program or generation patterns; regardless of the 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 
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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 

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 
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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 

percentageportion 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 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 &&&98 percentmost of the allowances 

to affected EGUs. Of this 98 percent that EPA proposes to 

allocate directly to affected EGUs, the agency proposes to 

allocate most of the allowances using a historic-generation 
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based approach and to distribute a percentage (the percentage 

varies by state, as. The EPA is also proposing three set-asides 

of allowances, which are detailed in section V.D.3) using an 

updating output-based allowance set-aside,. As explained below, 

this proposed updating output-based set-aside is intended to 

prevent or mitigate potential emissions leakage to new fossilfueled units not covered by the mass-based plan. The EPA 

proposes to distribute the remaining &&&two percent of 

allowances to a set-aside pool of allowances for renewable 

energy projects, as described 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 categorysubcategory

level. In developing the Clean Power Plan EGs, the agency 

conducted analysis of emission reduction potential in the two 

affected EGU source categoriessubcategories, 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 by source categoryinto 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 
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of historic generation. This alternative is described later in 

this section.

The EPA recognizes that states may prefer different 

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 how 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 preamble, respectively.96. 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-

 

96 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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plan allowance-distribution provisions with its own allowancedistribution provisions is 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, twothree proposed allowance setasides, 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, while setting. The EPA also 

proposes three allowance set-asides. The first would set aside a 

percentageportion 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 
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allowances in each compliance period except for the first 

period; the EPA proposes to be allocated distribute allowances 

from this set-aside to affected EGUs via an updating outputbased set-aside (the size of the set-aside would vary by state), 

and setting aside twoapproach as detailed in section V.D.3 of 

this preamble). The third would set aside 5 percent of 

allowances in each state, in all compliance periods, to be 

distributed to RE 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 projects. In the first compliance 

year, the EPA would allocate &&&98 percent of 

allowances using the historic-data based approach

(i.e., all except two percent for the RE set-aside in 

each state), because the EPA does not propose to 

include the output-based set-aside in the first 

compliance period. The EPA proposes to include the 

output-based set-aside starting with the second 

compliance period. The EPA proposes that the size 

(number of allowances) of a state’s output-based setaside would remain the same across each compliance 

period; the set-aside share would increase relative to 

the total allowances in a state as the mass goals 

decrease with the steps in the Interim Period. The 

proposed set-asides are detailed in section V.D.3. 

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 
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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 

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 two

set-asides97) to individual affected EGUs based on each affected 

EGU’s share of the state’s historic generation, using a 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 affected-EGU-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 zero.98 (See step 2, below, for how zero 

 

97 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.

98 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 
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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 emission guidelinesEGs

(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 unitspecific 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 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 affected EGU’s share of the state’s 

total average historic generation.

 

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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(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-aside for output-based allocations, and 

minus the set-aside for renewable energy projectsasides) to 

determine that affected EGU’s allocation.

For the first compliance period, the historic-generationallocation portion of the state’s mass goal would comprise 

the mass goal minus only the set-aside for renewable 

energy, as the output-based set-aside would not commence 

until the second compliance period.

The agency believes that this proposed historic-generationbased allocation approach is a reasonable approach for several 

reasons:

• The agency believes that the proposed historic-generationbased 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-EGU-level 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 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 [&&&reference 

to BaselineCO2 Emission Performance Rate and Goal 
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Computation TSD from final EGs].for CPP Final Rule. The 

majority of the generation-unit-level 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 affectedEGU-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 Program, and Cross-State Air Pollution Rulethe ARP, and 

CSAPR, based on historic data. For all these reasons, the agency 

believes that it is appropriate to use a historic-generationbased 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 
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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.

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 
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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 

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 
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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 

alternative approach would divide the total number of allowances 

from a state’s mass goal (minus the set-asides) byinto 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 
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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 

rate. The EPA promulgatedwould 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 Table 6 in section IV.B of this preamble, above. The EPA 

established the source category-specific CO2 emissions 

performance rates in the Clean Power Plan EGs [&&& cite to(see 

section VI of 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) 

byinto affected-EGU source categorycategories 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 historic-generation based approach described above, and 
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would also allocate the NGCC-unit portion of the allowances to 

individual NGCC units using the historic-generation based 

approach. are

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 

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.99 Alternatively, 

allocations could be distributed based on projected or observed

future activity (e.g., generation, heat input, or emissions); 

for the reasons stated above in the description of the historicgeneration-based allocation approach, the EPA believes the

approach is reasonable.).

 

99 Tools of the Trade, A Guide to Designing and Operating a Cap and Trade 

Program for Pollution Control, EPA, 2003.
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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.

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 
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investments in overburdenedlow-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.100 As a result, the EPA 

notes that states implementing state plans may have greater 

flexibility than the 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 Onecomment on an alternative approach, 

which is allocating [&&&]%a portion of the allowances to loadserving entities (LSEs) rather than to affected EGUs. LSEs are 

the entities responsible for delivering power to retail 

consumers. LSEs include entities that are investor-owned, 

publicly owned, owned by rural electric cooperatives, as well as 

other entities.

 

100 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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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 as condition of receiving an 

allocation of 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. Economic theory indicates that direct allocation 

to generators could result in profits to generators that, 

despite receiving allowances free of charge, include in the 

price of a marginal unit of electricity sold some or all of the 

opportunity cost of having to surrender an allowance (which has 

an economic value) to cover emissions associated with producing 

that marginal unit of electricity. The EPA could apply this 

approach by conditioning the receipt of allowances by LSEs on 

the pass through to consumers of any allowance value. In 

addition, most LSEs are regulated by state public utility 

commissions that would have authority to ensure that the value

of allowances directly allocated to LSEs be passed through to 

ratepayers. Other LSEs that are publicly owned or are electric 
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cooperatives have governing structures that could ensure that 

allowance value be passed through to ratepayers. 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.

Some existing mass-based GHG emission programs allocate 

allowances to load-serving entities. For example, California’s 

GHG emissions program allocates allowances for free to 

distribution utilities on behalf of electricity ratepayers, with 

the goal of protecting electricity ratepayers.101 California’s 

regulations stipulate auction proceeds and allowance value 

obtained by an electrical distribution utility from these direct 

allocations “shall be used exclusively for the benefit of retail 

ratepayers of each electrical distribution utility...and may not 

be used for the benefit of entities or persons other than such 

ratepayers.”102Each distribution utility that receives an 

allowance allocation must submit an annual report describing how 

 

101 17 CCR § 95892.

102 Id.
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they complied with this provision in their disposition of any 

auction proceeds and allowance value received for the prior 

calendar year. 

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. Finally,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 number of allowances should be distributed to LSEs and 

what monitoring and reporting requirements may be necessary to 

support an effective program.

The EPA recognizes that allocation to LSEs, by reducing 

rate impacts, could reduce incentives for socially efficient 

demand response, including potential investment in energy 

efficiency. The EPA solicits comment on the magnitude of this 
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effect, relative to alternative allocation options, and design 

options that could help mitigate this effect.

The EPA requests comment on the proposed historicgeneration based allocation approach, the alternative approach 

that divides total allowances from a mass goal byinto source 

categorysubcategories 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 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 two proposed 

allowancesallowance 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 requirement 

that in a mass-based program where new sources are not included 
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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 two set-asidesaside allowances – is 

a one-time 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 

detailed below)). The EPA also proposes that a state could 

choose to replace the federal-plan allocations to its affected 
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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 seven7 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 

June1June 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.103

The final emission guideline outline concerns regarding EGs 

specify 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 of the BSER (e.g., the ratebased and mass-based state goals) to 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 incorporating the 

subcategory-specific emission performance rates representing the 

BSER. The final EGs specified as the risk of increasedthat massbased plan approaches 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 that can be caused when generation shifts

over time from affected EGUs under the rule to unaffected EGUs

(see Sec.VII.C). The final guidelines also acknowledge that 

therethe sector. These circumstances are shifts in generation 

across affected sources that could lead to greater or lesser 

 

103 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.
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emissions, and in fact the rule is premised on the shifting of 

emissions from higher-emitting to lower-emitting affected EGUs. 

The final guidelines also specify requirements for the 

implementation of rate-based and mass-based plans that minimize 

the risk of increased emissions from these generation shifts 

across affected sources.

However, there is still a key concern that under mass-based 

plans, generation may move from existing affected EGUs to new 

sources that are not affected by the final guidelines. This 

risk is not much less likely to be present for existing EGUs 

under a rate-based plan, because 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 and rate-based goals provide an incentive for 

low-emitting existing sources to maximize their utilization, and 

flexibilities under rate-based plans enable those unit to 

increase utilization by allowing those units to increase their 

emissions under the rate. This characteristic of rate-based 

plans also minimizes the concern of leakage from mass-based 

existing EGUs to existing EGUs in neighboring rate-based states, 

because the lower-emitting units in rate-based states will 

already be incented to maximize their utilization, and thus will 

not have as much opportunity to increase their output to replace 

generation from existing units in mass-based states. But new 
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units in rate-based and mass-based states are more likely to 

have the opportunity to increase their utilization in order to 

replace generation from . By requiring mass-based plan 

components that address leakage, the final EGs ensure that massbased existing sources, and the mass-based affected EGUs won’t 

have the incentive to maximize utilization and they don’t have 

the opportunity to increase their emissions in the same way as 

rate-based existing EGUs. Therefore, leakage to new sources is a 

unique risk for mass-based plans and must be addressed in order 

to assure equivalency between goals are equivalent to the CO2

emission performance rates (as well as rate-based goals) and 

mass-based goals.

The final guidelines require that jurisdictions 

implementing a mass-based option make a demonstration that 

leakage has been addressed in their plan (See Sec.and 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 section VIII.L). TheJ of the final EGs specifies

options for making that demonstration include creating a mass 

limit that opts in new sources, implementing allocation 

strategies that address leakage, or justify why leakage is not a 

concern for the jurisdiction because of existing policy or 

unique characteristics. mass-based state plan components that 

address leakage. We are proposing, as part of the mass-based 
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approach under the federal plan and model rule, to implement 

allowance allocation approaches to address leakage through the 

use of allocations strategies, specifically the use of a 

combination ofthrough establishing an output-based allocation 

set-aside and a set-aside that encourages the installation of 

RE. In the section below, the EPA discusses why we have chosen 

set-aside allocation strategies as the approach to address 

leakage. 

Set-asides can be used to target and refine allowance 

allocation in order to achieve beneficial outcomes, for example 

ensuring program integrity and mitigating costs. As noted in the 

EG, if a state were to adopt allowance set-aside provisions 

exactly as they are outlined in this model rule once it is 

finalized, the requirement for that state plan to address 

leakage would be considered presumptively approvable.

Section VIII.J of the final EGs provides a discussion of 

how set-asides can effectively address leakage in a mass-based 

plan approach. That section of the final EGs also describes why 

the allowance allocation alternative for 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-
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fired sources under CAA section 111(d), and therefore we cannot 

include new sources under a federal mass-based plan approach.

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 order to support particular program 

goalsdesigned to address 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.104 The EPA believes these set-aside programs 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 

 

104 In designing a federal plan under CAA section 111(d), the EPA recognizes 

its authority as being, in some sense, the same as that 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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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 

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.105 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. 

 

105 See also EPA, Allowance Allocation Final Rule TSD, EPA-HQ-OAR-2009-0491, 

at 3-4 (June 2011).
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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, 

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.”106 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 

 

106 U.S. EPA, Acid Rain Program, Conservation and Renewable Energy Reserve, 

EPA 430-R-94-010 (Nov. 1994).
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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 

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.107 In general, the EPA believes its experience and those 

 

107 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_allowanc

e_6-6-2006.pdf. 
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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.108

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 the risk of increased emissions due to movement of 

generation to existing sources in neighboring states that adopt 

rate-based approaches, though the risk of 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 

 

108 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 

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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solicits comment on other set-aside options that could support 

the goals of the programaddress leakage, including a set-aside 

that provides an incentive for demand-side EE. The EPA seeks 

comment on all aspects of the set-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 emissions leakage to new units or existing 

units covered by a rate-based plan in a neighboring state.. The 

EPA believes that this proposed set-aside would help ensure the

environmental integrity of a mass-based plan, and could 

potentially reduce costs, and 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 
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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 

period. The allocation to an eligible EGU is not fixed, but 

instead depend on its generation.the previous compliance period.

Each eligible EGU maywould 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 analogous EGUs covered by emission rate limits, new 

emitting EGUs that are not subject to a mass-based limit, 

mitigating emissions leakage. The EPA also solicits comment on 

another potential ancillary benefit of this set-aside: 

mitigating electricity price impacts associated with the 
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proposed federal plan. Output-based allocation lowers the 

marginal production cost of eligible EGUs. Therefore, if these 

EGUs influence 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 output-based allocation approach be 

designed to avoid unintended consequences. In particular, the

design should reflect the fact that its application may reduce 

the incentives to invest in new zero- or low-emitting generation

as a result of the downward pressure it may place on electricity 

prices.

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 a large number of 

allowances for each MWh of generation this could incentivize

generation that is high cost, exclusive of the cost associated 
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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 

improved by targeting which units receive this additional 

incentive. In particular, this approach can most effectively 
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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, and EGUs not subject to the emissions guidelines,

would not receive output-based allocations from this set-aside.

Below we also take comment on whether sources other than 

combustion turbines sources subject to the emissions guidelines 

should be eligible for output-based allocations under this setaside. 

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 

capacity factor over the compliance period. The allocation rate 
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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 below this average capacity factor (although all 

affected EGUs will still receive allowances through the default 

allocation approach and any applicable set-aside). 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.109

The EPA proposes that each EGU for the set-aside receive outputbased allocation at the allocation rate only if its average 

capacity factor in the compliance period is above 50 percent on 

a net-basis [&&& check net]. 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 

 

109 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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to receive them.110 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.)

Next, the EPA 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 

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 

 

110 Effectively, the allocation rate of output-based allocation is zero up 

until this average capacity factor. 
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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. 

Weighing these observations, the EPA specifically proposes

allocating allowances based on generation from eligible EGUs in 

the preceding compliance period. 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.
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Further, we requestThe 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 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

(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 capacity-factor 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 set-
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aside 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.111

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 

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 

 

111 Effectively, the allocation rate (defined below) of output-based 

allocation is zero up until this average capacity factor.
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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, 

inclusive of allowances allocated through this OBA set-aside.112

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. In 

particular, we request comment on settingThe EPA proposes to set

the allocation rate equal to the emission rate standard (on a 

net -basis) for new stationary combustion turbinesNGCC 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 [&&&REF]..

 

112 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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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 &&&___lb/MWh-net.1,030 lbs/MWh-net (Carbon 

Pollution Standards for new, modified, and reconstructed EGUs).

The EPA requests comments on other values for the allocation 

rate. For example the allocation rate may be the expected net 

emissions rate of newly constructed NGCC units, the historic

average emissions rate from NGCC units, or the NGCC or fossil 

steam source category-specific emissions performance rates 

promulgated in the Clean Power Plan EGs (see section VI of the 

final EGs).

The EPA proposes to calculate allocations to NGCC units 

from the output-based set-aside using data from the preceding 

compliance period. For example, the EPA would calculate setaside allowances for the second compliance period (2025 through 

2027) based on data from 2022 through 2024. Each NGCC-unit

affected EGU with an average capacity factor above 50 percent in 

the preceding compliance period would earn set-aside allowances. 

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 
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requirements)..113 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 EPA; we 

would add EGU-level net summer capacity the EPA 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.H of this preamble). The 

EPA requests comment onnotes that the relative efficiency of 

obtainingEIA net summer capacity from data is reported to EIA or 

of adding net summer capacity as a requiredat the generator 

level; if we add this data field onpoint to the certificate of 

registration it would be reported at the affected-EGU level, 

which would facilitate calculation of 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.

After identifyingThe EPA proposes to determine the size of 

 

113 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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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 units with average to increase 

utilization to a 60 percent capacity factor above 50. The 

assumed 60 percent capacity factor offers a way to limit the EPA 

would then calculatesize of this set-aside, which allows the 

amountremainder of the allowances these affected EGUs would 

receive from the output-based set-aside as the unit’s net 

generation in the precedinga given compliance period multiplied 

by the 111(b) rate standard for NGCC units of &&&__lb/MWh-net. 

(The proposed to be allocated through the historic-generation

approach to determine the size of the set-aside is (as detailed 

below.)

The EPA proposes to provide notice of the capacity and 

generation data used,above) 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. 

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.
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The EPA requests comment on the proposed approach to 

calculate output-based set-aside allocations. Further details of 

the proposed approach are in the Allowance Allocation Proposed 

Rule TSD in the docket.

The EPA proposes a particular size of the set-aside that is 

based on the total allocation, the allocation rate, the capacity 

factor above which eligible generation may receive the outputbased allocations, and an average capacity factor across all 

sources potentially eligible for allowances from the set-aside. 

In particular, EPA proposes that the share of the total used for 

the set-aside be equal to the allocation rate, multiplied by the 

amount of potential generation from all EGUs eligible for the 

set aside in the state above an average capacity factor of 50

percent and below an average capacity factor of 70 percent, 

based on 2014 data other proposed set-asides (as detailed 

below.114 The 50 percent average capacity factor is the capacity 

factor above which eligible generation may receive the outputbased allocations. The 70 percent capacity factor limits the 

size of this set-aside, which increases the share of the 

allowances allocated based on historic-generation [&&& section

V.D.1]. Maintaining a large share of allowances allocated based 

on historic generation provides all EGUs subject to the mass-

 

114 The capacity eligible for the set-aside would be determined from data 

provided at the end of the previous compliance period. 
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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, as 

discussed further in the Allowance Allocation Proposed Rule TSD.

The EPA proposes to determine the size of the output-based 

set-aside for each state using 2012 baseline data reported to 

EIA forfrom the year 2014.Clean Power Plan EGs.115 The EPA would 

calculate the size of the set-aside as the sum of net generation 

from NGCC-unit affected EGUs that operated above 5010 percent 

and below 70 percentof the NGCC capacity factor in 2014the 

state116 multiplied by the 111(b)hours in a year multiplied by the 

allocation rate standardfor the set-aside. The EPA takes comment 

on the proposed capacity data used as the basis for determining 

the size of the output-based set-aside, and alternative sources 

of capacity data that may be used for NGCC units of &&&___ 

lb/MWh-net.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 

 

115 CO2 Emission Performance Rate and Goal Computation TSD for the CPP Final 

Rule.

116 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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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 setaside. 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

(Metric Tons)

The EPA proposes to determine for 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 FinalSecond 

Compliance 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 requests comment on this approach. 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
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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

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
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Wyoming 45,114

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 setaside 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. 

We propose 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 utility boiler. 

Output-based allocation for steam generating units may increase 

generation subject to the mass, leading to reduced generation 

from new emitting sources. However, the EPA does not propose 

this approach because it is not as effective as output-based 

allocation. This is because output-based allocation to utility

would incentivize generation from relatively high-emitting EGUs, 

thereby leading to high allowance prices, which then counteracts

the effect of lowering the cost of production of sources subject 
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to the proposed mass-based plan.117

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 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 set-aside should be drawn. 

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 

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 

 

117 This effect on the allowance price is also present when output-based 

allocation is limited to NGCC units, but because NGCC units have a lower 

emissions rate the effect is not as strong.
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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.

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 as part of, and is also 

proposed for the mass-based trading program,, if it is 

finalizedmodel 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 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 emission guidelines. First, theThis set-aside may is 

expected to address leakage concerns regarding leakage by 

lowering the marginal cost of production of the incented clean 

energy technologies within the state. All else being equal, this 
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lowers the cost of generation in the state, 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.This will 

make RE more competitive against new sources, reducing the 

potential for leakage to new sources. While the proposed setasides would provide additional incentive for the creation of 

additional RE capacity, it should also be noted that the 

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 usingIn 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 context 

of the proposed federal plan here, RGGI only covers a subset of 

states. The RGGI staff proposal recognized that reduced 

electricity demand can reduce the potential for emissions 
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leakage of generation from a participating to a nonparticipating state, by reducing the demand for fossil fuelfired electric generation, which in turn reduces the demand for 

CO2 allowances, and thus reduces allowance prices within the RGGI 

market.118 Under the RGGI program, more 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.119 While not a set-aside 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 , the EPA is proposing that it would create a 

unique set-aside would be created 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 

 

118 RGGI, Potential Emissions Leakage and the Regional Greenhouse Gas 

Initiative (RGGI), Final Report (March 2008), available at 

http://www.rggi.org/docs/20080331leakage.pdf.

119 RGGI, “Second Control Period CO2 Allowance Allocation,” March 25, 2015. 

Available at 

http://www.rggi.org/docs/CO2AuctionsTrackingOffsets/Allocation/SCP_AllowanceAllocation.pdf. RGGI, Investment of RGGI Proceeds through 2013, April 2015. 

Available at http://www.rggi.org/docs/ProceedsReport/Investment-RGGIProceeds-Through-2013.pdf.
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proposing that five5 percent of allowances will be reserved from 

the allocation for each state for the purpose of the set-aside. 

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 setaside allowances, and thus the provision of these set-asides 

does not affect the overall stringency of the program.

In Sec. &&§ion V.D.45 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 

are proposing, as part of the mass-based federal plan will have 
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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 or by unique characteristics of the jurisdiction.

We are proposingmodel rule, that a project is eligible to 

receive set-aside allowances if it is RE that meets the 

eligibility requirements for rate-based ERC issuance as 

specified in section IV.C of this proposal Sec. &&&preamble and

section VIII.K of the final guidelines Sec. VIII.&&&.EGs. 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

subject to the federal plan.

The EPA is proposing that eligible RE capacity must meet 

the following conditions regarding geographic eligibility. for 
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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 actions 

resultinggeneration for which an entity receives allowances from 

the set-aside would not be eligible to be counted as creditsfor 

ERC issuance in rate-based states. 

As specified in section IV.F.2C of this preamble, the EPA 

is proposing that the same RE measures are eligible to receive 

set-aside 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. 

All proposed aspects of the 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-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 
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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.F.2C of this preamble and the requests for comment 

included within that section also apply in the mass-based setaside context. for both the proposed mass-based 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 

technologies as eligibleemission 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 

the biomass eligibility options treatment requirements offered 

for comment in Sec.section IV.F.2 in a mass-based set-aside 

context. We also request comment on possible avenues to add new 
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technologies to this specified set of measuresC.3 of this 

preamble in the context of a mass-based set-aside. 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 40 CFR 62.16320 for the requirements to establish a general 

account. While the EPA is proposing to allow eligible resources 

to use a general account to receive any allowances allocated 
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under this section, the EPA requests comment on extending the 

designated representative provisions in 40 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 40 CFR

62.16305 and to appoint a designated representative to act on 

behalf of all owners/operators for all projects requesting 

allowances may be deposited.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 expost metered data). The projection method enables the 

distribution of set-aside allowances prior to the relevant 

compliance year whileduring which the generation occurs. The EPA 

feels this still provides sufficient rigor because the set-aside 

does not affectingdirectly affect program stringency. The reason 
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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 

recognize issue an ERC based on a quantification of RE with 

ERCsgeneration 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 

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 
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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 

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 MWh provided by the installation in a prior year or 
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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 compliance year in 

question.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-asides in any compliance period. 

If approved, the number of projected megawatt-hoursMWh in each 

compliancegeneration 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 
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opportunity to update projections for future 

compliancegeneration years, these projections must be received 

by June 1 of the year prior to the compliancegeneration 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 MWHsMWh 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 MWh of generation, such as 1 allowance per MWh.

After each compliancegeneration year, RE providers 

receiving allowances will have to provide an M&V report with the 

megawatt-hoursMWh 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
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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 

actual generationM&V reports with actual generation. 

If the project or program does not reach the megawatthoursMWh projected in a particular compliancegeneration year, 

the unfulfilled megawatt-hoursMWh will be subtracted from that 

RE provider’s MWhsMWh eligible for the set-aside in the next 

compliancegeneration 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 three3 years of the 

any complianceperformance 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 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 
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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 compliancegeneration 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

community, or the project lowering utility costs of low-income 

rate-payers. The EPA seeks comment on how a low-income 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 
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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) on behalf of a state by issuing early action allowances 

for eligible actions located in or benefitting the state. 

Eligible projects must commence construction in the case of RE 

or commence operations in the case of low-income EE after 

September 6, 2018, and will receive incentives based on the 

zero-emitting MWh they generate, or the energy savings they 

achieve,during 2020 and/or 2021.120 These early action allowances 

 

120 As discussed in section VIII.B.2 of the final emission 

guidelines, in the case of a state that submits a final state 

plan including requirements for the state’s participation in the 

CEIP, eligible RE projects may commence construction, and 

eligible EE projects may commence implementation, following the 

date of submission of a final state plan to the EPA. These 

projects must be implemented in or benefit the state that 
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would be drawn 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.121 See Table 10 of this preamble for the proposed setasides for each state under the mass-based federal plan. The 

agency proposes to set aside 100 million early action allowances 

from each of the 3 years in the first compliance period (2022, 

2023, and 2024) for a total of 300 million allowances to be set 

 

submitted the final state plan to the EPA, and may receive 

awards for the zero-emitting MWh they generate or the end-use 

energy savings they achieve during 2020 and/or 2021.

121 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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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 mass-based 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 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).

Eligible RE projects must commence construction, and 

eligible EE projects must commence implementation, after 

September 6, 2018 for those states on whose behalf the EPA is 

implementing the federal plan. These projects will receive 

incentives for the MWh they generate or the end-use energy 

demand reductions they achieve during 2020 and/or 2021.

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 federalplan states, as described above. Second, the agency proposes to 
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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. 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 states122 – 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 

 

122 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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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 is proposing that unused allowances in 

either reserve would be 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, 2018123 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. 

 

123 This may occur because not all states may elect to include requirements for 

CEIP participation in their state plans. 
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Unused matching allowances that remain in the accounts of states 

participating in the CEIP on January 1, 2023, will be retired by 

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 set-aside.

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 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 
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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 massbased 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 

allowance-distribution 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 statedetermined 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. 

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 
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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 low-income 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.

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
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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

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
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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 two2 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, starting 

in the fifth year after the first year of non-operation, would 

be allocated to the renewable energyRE set-aside for the state 

in which the retired unit is located.124 In other words, the 

retired unit would continue to receive allocations for four 

years after it ceases operation. Continuing allocations to nonoperating 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 

 

124 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 setaside; in CSAPR the set-aside is for new units.
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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 agency requests comment on this 

approach.

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 energy set-aside. The agency requests 

comment on a further alternative approach, which would be to 

continue allocations to the retired units.

Units that are modified or reconstructed. The EPA proposes 

that, if an affected EGU is modified or reconstructed such that 

it is no longer an affected EGU in the mass-based trading 

federal plan, the allowances that would otherwise have been 

allocated to that unit, starting in the first year after the 

year the unit is modified or reconstructed, would be allocated 

to the renewable energy set-aside for the state in which the 

unit is located [&&&will confirm this language based on final 

decision on treatment of modified/reconstructed units in EGs]. 

The EPA proposes to record allowances for each year of a 

multi-year compliance period at once, 7 months prior to the 
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start of each compliance period, as discussed above. The agency 

proposes that, if an affected EGU does not operate for 2 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 RE set-aside. As a result, the 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 3-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 RE

set-aside — in other words the unit would receive allocations 

for 3 years of non-operation. As a further example, if an 

affected EGU does not operate for both calendar years of a 2-

year compliance period, then starting with the compliance period 

after the next compliance period the allowances would be 

allocated to the RE set-aside — in other words the unit would 

receive allocations for 4 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 
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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 

agency requests comment on a further alternative approach, which 

would be to continue allocations to the modified or 

reconstructedretired units. The EPA also requests comment on 

treatment of allocations to units that are in long-term cold 

storage.

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 RE 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 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 RE

set-aside. The agency requests comment on a further alternative 
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approach, which would be to continue allocations to the modified 

or reconstructed units.

D. 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 thisthe state-determined 

allocation approach offers significant advantages and solicits 
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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 CAIR where the EPA adopted a rulerules 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 

CSAPR trading programs under the CSAPRthose 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 allowance-distribution 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 allowance-distribution provisions with allowancedistribution 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 

federal plan authority.) In general, under the proposed 

approach, the procedural requirements states and the agency must 
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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, section see sections VII.D and VIII.L).J 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, 

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 
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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 

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 
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methodology may also include other set-aside approaches that are 

not designed to counteract leakage.

The Clean Power Plan EGs established a Clean Energy 

Incentive Program (section VIII of 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 

determineddetermine 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 mass-based 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).

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 if the EPA finalizes a three-year compliance period..
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The EPA proposes that a state submitting a state allowancedistribution methodology to modify the federal plan allowancedistribution 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 

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 
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applicable mass goal.125 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 would have tomust provide for 

allowances to be issued in metric tons if EPA finalizes the 

proposed approach of issuing federal plan allowances in metric 

tons; the EPA proposes that a state allowance-distribution 

methodology would have to provide for allowances to be issued in 

short tons if the EPA finalizes the alternative of issuing 

federal plan allowances 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.

 

125 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 

EPAthe EPA’s recordation of allowances, for each compliance 

period. The EPA would review and approve state allowancedistribution 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 

unit-level 

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 
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unit-level allowance table, and not to wait until the allowance 

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 bywith 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 

partial delegation). The agency requests comment on whether the 
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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.

E. 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 

state might withdraw from the mass-based trading program in the 

middle of a compliance period even though allowances that 
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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

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 state-
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plan implementation, and on the trade-off between recording 

allowances in a timely way and providing this increased timing 

flexibility.

F. 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 

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 
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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 

Sections XX.XX through XX.XX 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 

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 
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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 

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 
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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 

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. 
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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 

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 
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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 

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. [citations needed]

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 
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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 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 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 
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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 

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
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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 NovemberMay 1, 2025 (the EPA is also 

requesting comment on anearlier or later allowance transfer 

deadline of June 1 or March 1deadlines). 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 

allowance transfer deadline –- need, 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 
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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 an 

affected EGU 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 obligation to comply in the current 

period. In addition, thethese 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 
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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 

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). 

G. Emissions Monitoring and Reporting Requirements
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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 Part40 

CFR 75.60. The use of 40 CFR 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 40 CFR part 75 as they have 

under 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 

Mercury and Air Toxics Standards (MATS) program and, therefore,
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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, 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 
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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.

The EPA also solicits comment on measures that could 

monitor the environmental integrity of a federal plan. As 

discussed previously in [&&&x], differences in generation 

incentives could lead to artificially increased generation by 

new EGUs or EGUs in neighboring states that are subject to 

different emission standards. Earlier sections discussed 

allocation options and other design strategies to address 

potential emissions leakage in a federal plan [&&&citation]. 

These efforts could be complemented by an emission and 

generation monitoring program that would help track key trends, 

suggest further design opportunities to support environmental 

integrity, and inform any related future decisions or policies. 

In particular, the EPA notes that the Regional Greenhouse 

Gas Initiative, in its founding MOU, specifically directed 

efforts to study this potential concern and provided 

recommendations to monitor emissions leakage. RGGI’s 

recommendations included producing detailed, periodic monitoring 

reports that tracked generation and its related environmental 

attributes, both for generation inside the RGGI region and 
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generation located outside the RGGI region but serving load in 

the RGGI region.126 These monitoring reports rely on information 

collected and tracked by independent system operators in 

generator attribute tracking systems. Part of RGGI’s 

recommendations included exploring necessary improvements to 

existing generator attribute tracking systems in order to 

support their ability to: determine how much electricity is 

being used in areas subject to RGGI (including supply by 

generation from within and outside of the RGGI region); 

determine and track the environmental attributes associated with 

those sources of generation, ideally reflecting the specific 

generation unit but alternatively based on applicable systemaverage attributes; identify units within the RGGI region and 

track their regulatory status; and other attributes. 

The EPA solicits comment on including a monitoring system 

to track program integrity as part of the federal plan. In 

particular, the EPA solicits comment on the agency’s legal 

authority to undertake relevant measures to develop and apply an 

appropriate monitoring program as part of the federal plan. The 

EPA also requests comment on the proper design of a program. 

Such a monitoring system could be used to track overall 

electricity consumed and generated in-state. It could also be 

 

126 http://www.rggi.org/docs/il_report_final_3_14_07.pdf.
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designed to track the demand that is being met by different 

categories of units serving load in-state: (1) in-state units 

covered by the federal plan; (2) in-state uncovered units; and 

(3) out-of-state units. At the same time, it would monitor the 

environmental attributes of electricity supply, either by 

developing systems to track the CO2 emissions performance 

associated with individual identified units, or by developing 

system-average emission rates for each of the three different 

categories of units serving in-state load.

This type of program could monitor environmental integrity 

by tracking changes in the CO2 emissions from generation not 

covered by the federal plan, i.e., uncovered in-state units or 

imports from neighboring states covered by different plans. One 

possible method would be to compare the change in emissions 

totals derived by multiplying the marginal increase in load 

served in-state by generation not subject to the federal plan by 

its applicable CO2 emission attributes compared to their historic 

or projected baseline generation. The EPA solicits comment on 

the existing availability of data on key indicators, options for 

acquiring and tracking any key data that is not yet widely 

available, and methods for analyzing that information to assess 

any potential change in environmental performance of a federal 

plan due to artificial differences in generation incentives.

VI. Implementation of the Federal Plan and Delegation
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Background of Authority

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 tribal127 plan or promulgates a federal plan 

that implements and enforces the EGEGs for affected EGUS in 

states notor areas of Indian country128 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 CAA

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

 

127 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) implementing the EG, but are 

not required to do so.

128 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 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 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.129 130 Delegation of the federal plan and 

Retained Authorities

A. Delegation of the Federal Plan and Retained Authorities

 

129 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.

130 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).
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If a state or tribe131 intends to take delegation of the 

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 ishas 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, 

 

131 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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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 

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 
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alternative requirement should submit a request to the Regional 

Administrator with a copy set to the appropriate state.

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 aan 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 aan 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

plan (sometimes called an “abbreviated state plan”) that may 
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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 planFlan

The EPA, in its discretion, may delegate to state or tribal 

air agencies the authority to implement this federal plan. As 

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 
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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 

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 
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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.EGs. Section 

301(d)(2) authorizes) of the CAA and 40 CFR part 49 authorize

the Administrator to treat an Indian Tribe in the same manner as 

a state for this EGU requirement (TAS).(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 comments from any of the 

affected tribes whether they are interestedwith EGU in their 

area of Indian country to comment on the level of their 

interest, if any, in developing their own planplans. 

The EPA is proposing in today’sthis action to find that it 

is necessary andor appropriate to regulate affected EGUs in each 

of the three areas of Indian country that have affected EGUs 

under the proposed federal plan. The EPA is authorized to 

directly implement the Clean Air ActEGs in Indian country when 

it determines pursuant tofinds, consistent with the authority of 

CAA section 301(d) and which the EPA has exercised in 40 CFR 

49.11, that it is necessary or appropriate to do so. In the 
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final Emission GuidelinesEGs, the EPA finalizedestablishes 

emission performance rates for the four EGUs located in Indian 

country and mass and rate-based emission goals for each of the 

three areas of Indian country with affected EGUs:areas of Indian 

country. These areas include lands of the Navajo NationNation’s 

reservation, lands of the Ute Tribe of the Uintah and Ouray 

Reservation, and lands of the Fort Mojave Tribe. [&&&citation to 

final EGs].Tribe’s reservation. 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, inon the Fort Mojave Indian countryReservation

geographically located within Arizona; the Navajo Generating 

Station, inon the Navajo Indian countryReservation

geographically located within Arizona; the Four Corners Power 

Plant, inon the Navajo Indian countryReservation geographically 

located within New Mexico; and the Bonanza Power Plant, in Uteon 

the Uintah and Ouray Indian countryReservation geographically 

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. 
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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 

plansplan that applyapplies 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 areasan 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, including Arizona, New Mexico, 

California, Texas, and Utah. . 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 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 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. To date, none of the 

three tribes on whose areas of Indian country the four power 

plants are located hashave expressed a clear intent to develop 
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and seek approval of a tribal implementation plan. Thus, absent 

a federal plan, the significant emissions from these four power 

plants wouldcould 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 pantsplants 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, 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 
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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 theany applicable federal plan. that is 

ultimately promulgated. In the event a federal plan is needed, 

proposing a necessary or appropriate determinationfinding 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 determination and/or a 

federal planfinding and/or a federal plan. Comments on the 

appropriateness of the proposed finding, should be submitted 
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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 

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

updates to the deadlines for the EPA action. In addition, in 
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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.132 Therefore, 

the EPA interprets CAA section 111(d) to provide the EPA 

flexibility in designing procedures that reflect the structure 

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.

 

132 See Webster’s II New Riverside University Dictionary (Riverside 1988) 

(defining “similar” to mean “resembling though not completely identical”).
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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 

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 
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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.133 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 

approvable. Another valuable function for This mechanism are 

those situations where the state wishes to take over a discrete 

part of a federal plan. For instance, in today’sthis 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 mass-based federal plan.

 

133 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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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 

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) 
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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. 

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 today’s 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. 
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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 decades. UnderdecadUnder

the Clean Power Plan EGs, states have many years 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 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 
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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 

finding and notice to the state available to the public.134

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 

 

134 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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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 

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 CAA 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 
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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” 

(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 CAA. 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 
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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 CAA’s requirements.

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 
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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 

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. 
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The EPA proposes that the administrative materials 

requirementboth groups would apply forto all CAA section 111(d) 

rules going forward. We propose technical-supportThe agency 

notes that the addition of completeness criteria that will only 

be applicable to state plansin the framework regulations does 

not alter any of the submission requirements states already have

under the Clean Power Plan EGs, at subpart UUUU. The EPA may in 

the future propose technical support criteria that are specific 

to future 111(d) rules.. 

For administrative materials, the EPA is proposing 

completeness criteria that mirror the existing administrative 

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:

(a (1) A formal letter of submittal from the Governor or 

her designee requesting EPA approval of the plan or revision 

thereof;

(b (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;

(c.); (3) Evidence that the state has the necessary legal 

authority under state law to adopt and implement the plan;
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(d 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;

(e (5) evidence that the state followed all of the 

procedural requirements of the state's laws and constitution in 

conducting and completing the adoption/issuance of the plan;

(f (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;

(g (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
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(h (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 EGs may provide otherwise. The technical support 

completeness criteria that the EPA proposes today are specific 

will also be generic to the CPP EGs at subpart UUUU. With 

respect to this set of completeness criteria, and consistentall 

CAA section 111(d) rules, with the structure of the CPP Emission 

Guidelines, EPA is organizing the proposed completeness criteria 

for technical support materials into three parts: components 

required for all CPP state plans; components required for the 

emission standards approach; and components required for the 

state measures approach.

same proviso. The EPA proposes that the technical support 

required for all plans must include each of the following:

(a (1) Description of the plan approach and geographic 

scope;

(b) ;(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 state CO2 interim period goal (for 

2022-2029), interim steps (interim step 1 for 2022-2024; interim 
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step 2 for 2025-2027; interim step 3 for 2028-2029)compliance 

schedules and final steps/or increments of 2030 and beyond;

(cprogress; (4) demonstration that the state plan submittal 

is projected to achieve the state’s CO2 emission goal; and

(demissions performance under the applicable EGs; (5) 

documentation of state recordkeeping and reporting requirements 

to determine the performance of the plan as a whole.

The EPA proposes that the technical support required for 

plans using the emission standards approach must include each of 

the following:

(a) Identification of each affected EGU, identification of 

federally enforceable emission standards for the affected EGUs, 

and monitoring, recordkeeping and reporting requirements that 

will determine compliance by each affected EGU; and

(b) Demonstrations; and (6) demonstration that each 

emission standard is quantifiable, non-duplicative, permanent, 

verifiable, and enforceable.

The EPA proposes that the technical support required for 

plans using the state measures approach must include each of the 

following:

(a) Identification of each affected EGU; identification of 

federally enforceable emission standards for affected EGUs (if 

applicable); identification of backstop of federally enforceable 

emission standards; monitoring, recordkeeping and reporting 
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requirements; and

(b) Identification of each state measure, demonstration 

that each state measure is quantifiable, non-duplicative, 

permanent, verifiable, and enforceable.

EPA proposes 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. 

As with the completeness determination process for SIP 

submissions, the EPA’s determination that a submittal is 
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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 Emission GuidelinesEGs, 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 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 
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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) Emission GuidelinesEGs, a state will submit all 

CAA section 111(d) plans electronically. If the EPA determines 

that any submission fails to meet the completeness criteria

discussed below, 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.

The EPA is also proposing to include an exception to the 

criteria for complete administrative materials in cases where a 
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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 EPAthe 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 

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 CPP Emission Guidelines, the requirements 

set 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 
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have not been met, as determined by 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

Finally,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 Emission GuidelinesCO2 EG for 

Electric Utility Generating Units (EGUs) have already adjusted 

the deadline in 60.27(b) to require the EPA to act on a state 

plan under those Emission GuidelinesEGs within 12 months (rather 

than 4 months) after the date required for submission of a plan. 

See 40 CFR 60.5715. However, the CPP Emission GuidelinesClean 
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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 required 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. 

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 
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60.27(d) to one1 year135; 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). 

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 

 

135 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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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 

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 40 CFR part 60, subpart UUUU. 
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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 

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. 
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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 

is, when CAA section 111(d) EGs 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) EGs. This interpretation gives meaning to the definition 
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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 

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 
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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 

Endangered Species Act (ESA), the EPA has also 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 
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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 

environmental baseline. 50 CFR 402.02. Direct effects are the 

direct or immediate effects of an action on a listed species or 

its habitat.136 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 the listed species, andif 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 

 

136 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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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 

Emission GuidelinesEGs that it implements, positive: reductions 

in overall GHG emissions, and reductions in PM and ozoneprecursor emissions (SO X and NO X), for EGUS that will be 

covered by the federal plan. 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 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 
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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 

GHG emissions and effects on the species in its habitat.137 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). EPA discussed this in the proposed Emissions 

Guidelines, see 79 FR 34933-34, notingIn the final EGs, the 

agency noted that, although the GHG emission reductions 

projected for the Emissions Guidelines wereEGs are large (the 

highest estimate isestimated reductions of 555 MMTabout 415

million short tons of CO2 in 2030 relative to the base case), the 

EPA evaluated larger reductions in assessing this same issue in 

 

137 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).
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the context of the light duty vehicle GHG emission standards for 

model years 2012-2016 and 2017-2025. EPA concluded there that it 

knew of “There the agency projected emission reductions over the 

lifetimes of the model years in question,138 which are roughly 

five to six times those projected above and, based on air 

quality modeling of potential environmental effects, concluded 

that “EPA knows of no modeling tool which can link these small, 

time-attenuated 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 EPAOAR-HQ-2009-4782); see also 79 FR 34934. The EPA believes that 

the same conclusions apply to the present proposal, given that 

the federal plan will implement only a subset of the reductions 

projected from the Emission Guidelines as a whole (i.e., for 

affected EGUs in states without approved plans), and the 

projected CO 2 emission reductions from the Emission Guidelines 

are less than those projected for either of the light duty 

vehicle rules. See). The EPA reached this conclusion after 

 

138 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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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. See 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 federal this 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 in the 

context of federal actions involving GHG emissions.

With regard to non-GHG air emissions, the EPA is also 

projecting substantial reductions of SOXSO2 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 Emission Guidelines.EGs. 40 CFR 
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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 thus 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 federal implementation planFIP for regional 

haze controls under section 169A of the CAA.).

Finally, EPA considered whether any other relevant effects 

(beyond reduction in air pollutants) may result from the 

establishment of standards of performance for existing affected 

EGUs and implementing and enforcing those standards. In this 

respect, this proposal is different from the Emissions 

Guidelines in that it would set in place a federal plan that 

will set standards of performance and provide for their 

implementation and enforcement for affected EGUs not covered by 

state plans. In the Emissions Guidelines proposal, EPA 

recognized that “there are substantial questions as to whether 

any potential for relevant effects results from any element of 

the proposed rule or would result instead from the separate 
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actions of states establishing standards of performance for 

existing sources and implementing and enforcing those 

standards.” See 79 FR 34934. Under a federal plan, it is EPA 

that would implement a 111(d) plan.

Finally, the EPA has also considered other potential 

effects of the rule (beyond reductions in air pollutants) and 

whether any 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 
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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 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. 

First,: (1) The EPA cannot know with any certainty at this 

statestage 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. Second,; 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 
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pollutant at historical rates so long as the affected EGU holds 

sufficient credits or allowances. At this stage,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 on potential 

future speculative effects.139 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? 

 

139 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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The EPA anticipates significant emission reductions under 

this proposed action for the utility power sector. Specifically, 

the EPA is proposing approaches in the form of mass- and ratebased 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 Clean Power Plan EGs. 

However, at the time of this proposal, the EPA has no 

information on whether any or how many states will require a 

federal plan or will adopt a model rule. Because of this lack of 

information, in the Regulatory Impact Analysis (RIA) for this 

proposal, 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. The first federal 

plan approach assumes all states in the contiguous U.S. are 

regulated under a rate-based federal plan. The second federal 

plan approach assumes all contiguous states are regulated under 

a mass-based federal plan.140

 

140 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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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 

proposal 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 12 and Table 13 of this preamble

show expected CO2 and other air pollutant emissions in the base 

case and reductions under the proposal for 2020, 2025, and 2030 

for both rate-based and mass-based approaches.

Table 12. Summary of CO2 and Other Air Pollutant Emission 

Reductions from the Base Case under Rate-Based Federal 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
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Emissions Reductions 415 318 282

Source: Integrated Planning Model, 2015. 

Note: Emissions may not sum due to rounding.

Table 13. Summary of CO2 and Other Air Pollutant Emission 

Reductions from the Base Case under Mass-Based Federal 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

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

[PLACEHOLDER: IMPACTS TO BE BASED ON ANALYSIS FOR 111D FINAL 

RULE]

Source: Integrated Planning Model, 2015. 

Note: Emissions may not sum due to rounding. 

The reductions in Tables 12 and 13 of this preamble do not 

account for reductions in 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? 
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The proposed action may have important energy market 

implications. Table 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 federal plan approaches

described in section VIII.C of this preamble and presented in 

the RIA for this proposal. 

Table 14. Summary Table of Important Energy Market Impacts for 

Rate-Based and Mass-Based Federal Plan Approaches (Percent 

Change from Base Case)

Rate-Based Mass-Based

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%

[PLACEHOLDER: IMPACTS TO BE BASED ON ANALYSIS FOR 111D FINAL 

RULE]

These figures reflect the EPA’s modeling that presumes 

policies that lead to generation shifts and growing use of DS-EE
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and renewable electricity generation out to 2029. If different 

implementation choices are made than those modelled, impacts 

could be different. 

D. What are the Compliance Costs?

[PLACEHOLDER: IMPACTS TO BE BASED ON ANALYSIS FOR 111D FINAL 

RULE]

The compliance costs of this proposed action are 

represented in this analysis as the change in electric power 

generation costs between the base case and modeled 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 DS-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 to be $2.5 billion in 

2020, $1.0 billion in 2025 and $8.4 billion in 2030. The EPA 

estimates the annual incremental compliance cost for the massbased federal plan approach to be $1.4 billion in 2020, $3.0 

billion in 2025 and $5.1 billion in 2030. More detailed cost 
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estimates are available in the RIA included in the rulemaking 

docket. 

E. What are the Economic and Employment Impacts?

[PLACEHOLDER: IMPACTS TO BE BASED ON ANALYSIS FOR 111D FINAL 

RULE]

Based 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 14 of 

this preamble for a variety of important energy market impacts 

for 2020, 2025, and 2030 under both the rate-based and massbased federal plan approaches described in Section VIII.B in 

this preamble and presented in the RIA.

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 DS-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.
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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. While the economy continues to move 

toward full employment, employment impacts are of particular 

concern and questions may arise about their existence and

magnitude. 

The EPA’s employment analysis includes projected employment 

impacts associated with modeled federal plan approaches for the 

electric power industry, coal and natural gas production, and 

DS-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 the proposed action could result 

in a net decrease of approximately 25,000 job-years in 2025 

under the rate-based federal plan approach and approximately 

26,000 job-years in 2025 under the mass-based approach. For 
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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 potential employment effects due to DS-EE

programs. Employment impacts from DS-EE programs in 2030 could 

range from approximately 52,000 to 83,000 jobs under the 

proposal. 

By its nature, DS-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 
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resulting from cleaner air. For these 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 proposed 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 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 cobenefits 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 co-benefits for the mass-based 

federal plan approach are estimated to be $5.3 to $8.1 billion 
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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 15 through 17 of this 

preamble.

Table 15. Summary of the Monetized Global Climate Benefits for 

the Proposal (Billions of 2011$)a

Year

Discount Rate 

(Statistic)

Monetized Climate Benefits

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

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 nonCO2 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. 
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Table 16. Summary of the Monetized Health Co-Benefits in the 

U.S. for the Proposal, Rate-based Federal Plan Approach 

(Billions of 2011$)a

Pollutant

National 

Emission 

Reductions 

(thousands 

of short 

tons)

Monetized 

Health Cobenefits

(3 percent 

discount)

Monetized 

Health Cobenefits

(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

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
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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 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 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 proposed 

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 co-benefits 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.

Table 17. Summary of the Monetized Health Co-Benefits in the 

U.S. for the Proposal, Mass-based Federal Plan Approach 

(Billions of 2011$)a

Pollutant

National 

Emission 

Reductions 

(thousands 

of short 

tons)

Monetized 

Health Cobenefits

(3 percent 

discount)

Monetized 

Health Cobenefits

(7 percent 

discount)
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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

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

[PLACEHOLDER: IMPACTS TO BE BASED ON ANALYSIS FOR 111D 

FINAL RULE]
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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 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 proposed 

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 co-benefits 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 

Analysis Under Executive Order 12866 (May 2013, Revised July

2015) (“current TSD”) to analyze CO2 climate impacts of this 

rulemaking.141 We refer to these estimates, which were developed 

 

141 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 
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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 

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 

 

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/scc-tsd-final-july2015.pdf.
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2013 using new versions of each IAM. The 2010 SC-CO2 Technical 

Support Document (2010 TSD)142 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 

minor corrections to the estimates).143

OMB’s Office of Information and Regulatory Affairs received 

comments in response to a request for public comment on the 

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 RIA.144

With the release of the response to comments, the IWG announced 

plans to obtain expert independent advice from the National 

 

142 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.

143 The current version of the TSD is available at: 

https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-response-tocomments-final-july-2015.pdf, 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).

144 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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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 

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. 
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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 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 RIA, including for this 

proceeding.

The four SC-CO2 estimates are as follows: $12, $40, $60, and 

$120 per short ton of CO2 emissions in the year 2020 (2011$).145

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 

 

145 The current version of the TSD is available at: 

https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-tsd-finaljuly-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/ECONI-2013-02/pdf/ECONI-2013-02-Pg3.pdf.
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SC-CO2 distribution (representing less likely, but potentially 

catastrophic, outcomes).

There are limitations in the estimates of the benefits from 

this 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 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 benefit-cost 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 
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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 federal plan approaches examined in the RIA for this 

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 Clean 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 BenMAP146 to calculate average regional benefit-per-ton 

estimates using the health impact assumptions used in the PM 

 

146 http://www.epa.gov/airquality/benmap/index.html.
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NAAQS RIA147 and Ozone NAAQS RIAs.148,149 The three regions were the 

Eastern U.S., Western U.S., and California. To calculate the cobenefits for this proposal, we multiplied the regional benefitper-ton estimates generated from modeling of the proposed Clean 

Power Plan EGs standards by the corresponding regional emission 

reductions for this proposal.150 All benefit-per-ton estimates 

reflect the geographic distribution of the modeled emissions for 

the proposed Clean Power Plan EGs, which may not exactly match 

the emission reductions in this proposed 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 

 

147 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.

148 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>.

149 U.S. Environmental Protection Agency (U.S. EPA). 2010. Section 3: Reanalysis of the Benefits of Attaining Alternative Ozone Standards to 

Incorporate Current Methods. Available at: 

http://www.epa.gov/ttnecas1/regdata/RIAs/s3-supplemental_analysisupdated_benefits11-5.09.pdf. 

150 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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information regarding the derivation of the benefit-per-ton 

estimates is available in the Clean Power Plan Final Rule RIA. 

PM benefit-per-ton values are generated using two 

concentration-response functions, Krewski et al. (2009)151 and 

Lepeule et al. (2012)152. 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, 

 

151 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.

152 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)153 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)154 and the upper end based on a 

benefit-per-ton estimate using the function from Levy et al. 

 

153 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.

154 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).155 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,156 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. 

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. 

 

155 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.

156 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 EPA600-R-08-139F, December). Available at: 

http://cfpub.epa.gov/si/si_public_record_Report.cfm?dirEntryId=216546.
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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,157 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. 

(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. 

 

157 In addition, site-specific emission reductions will depend upon how states 

implement the guidelines.
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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 this 

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 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. 

We note that the monetized co-benefits estimates shown here 

do not include several important benefit categories, including 

exposure to SO2, NOX, and HAP (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, 
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we include a qualitative assessment of these unquantified 

benefits in the RIA for this proposal. In addition, in the RIA 

for this 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 Clean 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 Considerations 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 

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 
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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 overburdenedvulnerable 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. 

This rule will bring other important benefits to

communities across the nation. Vulnerable communities also often 

receive more than their fair share of conventional air 

pollution, with the attendant adverse health impacts.

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. This benefitThese air quality improvements will 

be achieved through the rulemakingthis 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 
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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.158 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 overburdened communities.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 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 GHG 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 

 

158 Six Common Air Pollutants. http://www.epa.gov/oaqps001/urbanair/
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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 certainsome 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 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 assess any emissionsconduct an assessment of whether and 

where emission increases that may result from plan

implementation and mitigate adverse impacts, if any, in 

overburdened communities.
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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 investinvestment 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 

extent that 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. InThis input has informed this 

proposedfinal rulemaking we address many ofand prompted the 
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concernsEPA to consider other steps that were raised. One 

example is that commenters are concerned about the health, 

economic, and environmental impacts of climate change, but also 

want to ensure thatagency can take in the benefits of this 

rulemaking are shared fairlyshort and that low incomelong term 

to assist states and stakeholders to consider EJ and impacts to

communities are not adversely affected by the increased costs of 

electricity. In this section, we respond to these concerns.in 

plan development and implementation. 

We are workingIt 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. 

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 
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fundamental to beginning that process, the EPA has conducted ana

proximity analysis for this proposed rulemaking that summarizes

demographic data on the communities located near power plants, 

which we refer to as a proximity analysis.159 The EPA understands 

that, in order to prevent disproportionate,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 

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 

 

159 The proximity analysis was conducted using the EPA’s environmental justice 

mapping and screening tool, EJSCREEN.
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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 

power plants and in order to adequately capture both the lowincome and minority aspects central to environmental justiceEJ

considerations, we will use the termterms “vulnerable” or

“overburdened” when referring to these communities. Our intent 

is for this termthese terms to be understood in an expansive 
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sense, in order to capture the full scope of communities, 

including tribalindigenous communities most often located in 

rural areas, whichthat 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 

guidelinesstandards for existing affected fossil fuel-fired 

power plants. The EPA also believes that the information 

provided in the proximity analysis will promote engagement 

between overburdenedvulnerable 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 EPA Community Climate 

Protection Portal of the Clean Power Plan Website.Clean Power 

Plan (CPP) Communities Portal that will be linked to this 

rulemaking’s Web site (http://www.epa.gov/cleanpowerplan).

Furthermore, the EPA has also created an interactive mapping 

tool that illustrates where power plants are located and 

provides information on a state level. This tool is available 

at: http://cleanpowerplanmaps.epa.gov/CleanPowerPlan/.

B. Community Engagement in This Rulemaking Process 
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The EPA has heard from overburdenedvulnerable communities

throughout the outreach process for the Clean Power Plan that it 

is imperative for overburdened communities to have an 

understanding of how rulemakings that target climate change 

work. They expressed a desire to know how these 

rulemakingsprograms may benefit their communities and what the 

potential adverse impacts of the rulemakingrules may be on their 

communities. It is importantWe intend to the EPA that the agency 

provides overburdenedprovide 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 affected communities 

in the early stages of the comment period. The goal of this 

webinar will be to walk overburdened communities through the 

highlights of the preamble, so they have an understanding of how 

the rulemaking may potentially impactaffect their 

communitycommunities and they will have the contextual 
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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 overburdened communities. The goal of these 

meetings is to build a level of understanding on this rulemaking 

to enable overburdenedvulnerable 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 overburdenedvulnerable 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 

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.
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As discussed below, there are also many federal programs 

that can help overburdenedlow-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 overburdenedlow-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 also

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 overburdenedvulnerable

communities gain the benefits of this rulemaking. The use of 

these RE/EE tools can also overburdenedhelp low-income

households reduce their electricity consumption and bills. 

Additionally, as part of the resources that we will be 

providing overburdenedlow-income communities, the EPA will 

provide information on the White House’s Adminstration’s 

Partnerships for Opportunity and Workforce and Economic 

Revitalization (POWER Initiative) Initative and other programs 

that specifically target economic development assistance to 
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communities affected by changes in the coal industry and the 

utility power sector.160

D. Federal Programs and Resources Available to Communities

Federal agencies have a history of bringing energy 

efficiencyEE and renewable energy RE to low-income 

communities. Some examples of federal programs that offer 

resources 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. DOE, the U.S. Department 

of Housing and Urban Development, U.S. Department of 

Agriculture, 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 moderate- income communities. The Administration 

also set a goal to install 300 MW of RE in federally subsidized 

housing by 2020 and plants to provide technical assistance to 

make it easier to install solar energy on affordable housing, 

including clarifying how to use federal funding for EE and RE. 

To continue enhancing employment opportunities in the solar 

 

160 http://www.eda.gov/power/.
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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 EE and 

accelerate the deployment of RE 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 Housing and Urban Development’s goal (under the 

President’s Climate Action Plan) of installing 100 megawatts of 

RE across federally subsidized housing by 2020, the Department 

of Agriculture’s Energy Efficiency and Conservation Loan 

Program, and the Environmental Protection Agency’sHigh Cost 

Energy Grant Program, and the Rural Housing Service’s MultiFamily Housing Program.

The U.S. Department of Housing and Urban Development

supports EE improvements and the deployment of RE 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 Grants. The Department of Treasury 

provides several tax credits to support RE development and EE in 
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low-income communities, including the New Markets Tax Credit 

Program and the Low-Income Housing Tax Credit. The EPA’s REPowering America’s Land Initiative. promotes the reuse of 

potentially contaminated lands, landfills and mine sites – many 

of which are in low-income communities – for RE 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 EE 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 overburdenedstates and vulnerable

communities have access to information on these programs and 

their resources.

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 the U.S. 

Department of Housing and Urban Development, DOE, and the 
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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.161 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 

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 

 

161 76 FR 48348.
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and national basis.162 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 guidelinesstandards

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

or 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 guidelinesstandards for affected existing fossil fuelfired EGUs can be expected to cause more such changes. Increased 

utilization of 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 

 

162 76 FR 48347.
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that the gas-fired 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 gas-fired 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.”163 Because gas-fired EGUs emit essentially no 

mercury, increased utilization will not increase methyl mercury 

concentrations in water bodies near these affected EGUs. In 

studies done by DOE/NETL comparing cost and performance of coaland 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.164 Many, although 

 

163 65 FR 79831.

164 “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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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 

communitiesby 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.

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 
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and communities to monitor any disproportionate emissions that 

may result in adverse impacts and address them. 

EPAG. 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 overburdenedvulnerable communities. 

Throughout the implementation phase of this rulemaking, the 

agency will continue to provide trainings and resources to 

assist overburdened communities and as they engage with the 

agency. The EPA, through its outreach efforts during the comment 

period, will continue to solicit feedback from overburdened 

communities on what they would like additional trainings and 

resources on.

As described above, the EPA will assess the impacts of this 

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 EPA Community Climate ProtectionClean 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 overburdened communities understand the 

breadth of policy options and programs that have successfully 

brought EE/RE to overburdenedlow-income communities. The EPA is 
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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.165 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, 

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 

 

165 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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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.

A. Executive Order 12866: Regulatory Planning and Review and 

Executive Order 13563: Improving Regulation and Regulatory 

Review 

[&&&based on preliminary analysis]

This proposed action is an economically significant 

regulatory action that was submitted to the Office of Management 

and Budget (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, “[&&&insert title of 

document],”This analysis, which is contained in the “Regulatory 

Impact Analysis for the Proposed Federal Plan Requirements for 

Greenhouse Gas Emissions from Electric Utility Generating Units 
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Constructed on or Before January 8, 2014; Model Trading Rules; 

Amendments to Framework Regulations” (EPA-452/R-15-006, July 

2015), is available in the docket. and is briefly summarized in 

section VIII of this preamble. 

Consistent with EOExecutive Order 12866 and EOExecutive 

Order 13563, the EPA estimated the costs and benefits for 

illustrative compliancetwo alternative federal plan approaches 

ofto implementing the proposed federal plan and model trading 

rules. The proposed action will achieve the same levels of 

emissions performance as required of state plans under the CAA 

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 cobenefits, as these reductions are not the primary objective of 

this rule and federal plan.

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 mass-based 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 
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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.

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 
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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. 

The EPA estimates that, in 2020, the proposal 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 ratebased 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 compliance costs estimated by IPM and 

inclusive of DS-EE program and participant costs and MRR costs 

in 2020, are approximately $2.5 billion for the rate-based 

approach and $1.4 billion for the mass-based approach (2011$). 

The quantified net 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 
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mass-based approach, using a 3 percent discount rate (model 

average).

The EPA estimates that, in 2025, the proposal 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 ratebased 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 compliance costs estimated by IPM and 

inclusive of DS-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 massbased approach, using a 3 percent discount rate (model average).

The EPA estimates that, in 2030, the proposal will yield 

monetized climate benefits (in 2011$) of approximately $20 
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billion for the rate-based approach and $20 billion for the 

mass-based approach (3 percent model average). For the ratebased 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 compliance costs estimated by IPM and inclusive 

of DS-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 18 and Table 19 of this preamble provide the 

estimates of the climate benefits, health co-benefits, 

compliance costs and net benefits of the proposal for rate-based 

and mass-based federal plan approaches, respectively.
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Table 18. Summary of the Monetized Benefits, Compliance Costs, 

and Net Benefits for the Proposal in 2020, 2025 and 2030

Under the Rate-Based Federal Plan Approach [Billions of 2011$]a

Rate-Based Approach

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

Non-Monetized 

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 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 year-specific 

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 
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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 Costs are approximated by the compliance costs estimated using the IPM for 

this proposal and a discount rate of approximately 5 percent. This estimate 

includes monitoring, recordkeeping, and reporting costs and DS-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 19. Summary of the Monetized Benefits, Compliance Costs, 

and Net Benefits for the Proposal in 2020, 2025 and 2030

Under the Mass-Based Federal 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

Air Quality 

Health Cobenefitsc

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

$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

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.
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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 year-specific 

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 Costs are approximated by the compliance costs estimated using the 

Integrated Planning Model for this proposal and a discount rate of 

approximately 5 percent. This estimate includes monitoring, recordkeeping, 

and reporting costs and DS-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 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 GHGs (e.g., nitrous oxide and methane) and co-benefits 

from reducing direct exposure to SO2, NOX, and HAP (e.g., 

mercury), as well as from reducing ecosystem effects and 

visibility impairment. Based upon the foregoing discussion, it 
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remains clear that the benefits of this proposed action are 

substantial, and far exceed the costs. Additional details on 

benefits, costs, and net benefits estimates are provided in the

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 

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: 
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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 

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 
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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 the EPA cannot determine at this time how many 

affected EGU respondents will submit information under the 

federal plan, the 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 below:

Respondents/affected entities: 1,028

Respondents’ 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.
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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 

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 
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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. The 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 

unit-level estimates using IPM results for 2030.

The 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.

The 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 
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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, the EPA used the parsed unitlevel 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 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 
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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 

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 
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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 

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, the 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 
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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. 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.
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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. 

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 one1 year. 

Accordingly, the EPA has prepared the written statement required 

under section 202 of UMRA that This 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 
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the docketRIA for this action and briefly summarized here. 

[&&&Insert a concise summary of the written statement including 

a brief description of the intergovernmental consultation.]

the 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, the EPA cannot 

determine whether this final rule will be subject to UMRA. 

However, as noted below, the Agency has done substantial 

outreach to government entities as part of both the federal plan 

and the related CAA section 111(d) rulemaking. Further, 

regardless of whether the 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 
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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 the EPA developed the 

rule about how the EPA should approach the complex question of 

how to 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 
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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 

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 emission guidelinesEGs 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 
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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.

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 unitsEGU potentially impacted by this proposed rulemaking 

located on tribal landsIndian 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 unitEGU. 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 
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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 that a proposed 

federal 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 itsthe supplemental proposal. 

The agency also held itsa public hearing on the supplemental 

proposal on November 19, 2014, in Phoenix, ArizoniaArizona. At 

this timethe public hearing the agency received oral comments 

from community members representing a number of tribes and a 

number of tribal officalsofficials. 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.
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Additionally, the EPA engaged in meaningful dialogue with 

tribal stakeholders to obtain their feedback in the prepropsalproposal stages of this the rulemaking. We provided an 

update 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. As required by section 7(a), the EPA’s Tribal 

Consultation Official has certified that the requirements of 

Executive Order 13175 have been met in a meaningful and timely 

manner. A copy of the 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. In sections II.A, III.F and VI.E of this 

rulemaking the The EPA references tribes and specifically 

solicits additional feedback from tribal officials we invite 

comments from anyon all aspects of this proposed rulemaking, 

including whether tribes whose areas of theIndian country 

contain affected tribes whether theyEGU(s) are interested in 

developing their own plan. implementing the final EGs.
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Additionally, tribal stakeholders will be included in the 

outreach that the agency will be conducting with those 

communities already overburdened communities, that isby 

pollution, which are often low-income communities, communities 

of color, and indigenous communities. The actions that the 

agency will be taking are outlined in VI.Esection IX of this 

preamble.

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

[PLACEHOLDER: RESPONSE TO BE BASED ON ANALYSIS FOR 111D FINAL 
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RULE]

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 

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: 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 
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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 

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 
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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 

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 
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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 

scientific understanding of climate change risks to minority 

populations and low-income populations in the United StatesU.S.166

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 

 

166 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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communities of color may be uniquely vulnerable to climate 

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 guidelinesstandards 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 energy.RE. 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,167 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 risksusceptibility to PM-related and 

ozone-related effects.168 Therefore, 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 effects associated with these emission 

reductions. 

 

167 “National Ambient Air Quality Standards for Particulate Matter, Final 

Rule,” 78 FR 3086 (Jan. 15, 2013).

168 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?dirEntryId=216546.
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Additionally, as outlined in the community and EJ

considerations section IX of this preamble, the agency 

believesEPA has taken a number of actions to help ensure that 

all communities, including overburdened communities will benefit 

from this rulemaking because of the direct health benefits 

associated with the CO2 and conventional pollutant reductions. 

Furthermore, this action will complement EPA actions already in 

place to address conventional pollutant emissions and will 

result in further positive health benefits for overburden

communities. To help in the identification of those communities 

overburdened by this rulemaking as noted in section IX.A of this 

preamble, the EPA has conducted a proximity analysis for this 

rulemaking, which is located in the docket.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 

craftingdetermining what actions to take.169 As described in the 

community and EJ 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 

 

169 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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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.
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

Page 515 of 515

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.