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During Review***

EO12866_CPP Federal Plan 2060 AS47 NPRM_20150801

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 Rules; Amendments to Framework 

Regulations

AGENCY: Environmental Protection Agency.

ACTION: Proposed Rule.

SUMMARY: In this action, the Environmental Protection Agency 

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

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

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

August 3, 2015 as the Carbon Pollution Emission Guidelines for 

Existing Stationary Sources: Electric Utility Generating Units 

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

presents two approaches to a federal plan for states and other 

jurisdictions that do not submit an approvable plan to the EPA: 

a rate-based emission trading program and a mass-based emission 

trading program. These proposals also constitute proposed model 
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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 carbon 

dioxide (CO2) emission performance rate for steam-fired EGUs and 

a 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 equivalent statewide goal, in order 

to achieve reductions in CO2 emissions in the case where a state 

or other jurisdiction does not submit an approvable plan. The

stringency of the emission performance levels established in the 

final EGs will be the 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 the rate-based and mass-based 

model trading rules in summer 2016.
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DATES: Comments. Comments must be received on or before [insert 

date 90 days after date of publication 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.

• Mail: Send your comments to: Environmental Protection 

Agency, EPA Docket Center (EPA/DC), Mailcode: 28221T, 1200 

Pennsylvania Ave., NW, Washington, DC 20460, Attention 

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

Room 3334, EPA WJC West Building, 1301 Constitution Ave., 

NW, Washington, DC, 20004, Attention Docket ID No. EPA-HQOAR-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.
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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 

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 
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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 

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 
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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.

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 
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to on-site schedule fluctuations, actual speaking times may 

shift slightly.

Because these hearings are being held at United States 

(U.S.) government facilities, individuals planning to attend the 

hearing should be prepared to show valid picture identification 

to the security staff in order to gain access to the meeting 

room. Please note that the REAL ID Act, passed by Congress in 

2005, established new requirements for entering federal 

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

American Samoa, Arizona, Kentucky, 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 
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asked to remove all items from all pockets and place in provided 

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

devices from their carrying case and place in provided bins for 

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

supports as a part of their construction; remove any metal 

belts, metal belt buckles, large jewelry, watches; and follow 

the instructions of the guard if identified for secondary 

screening. Additionally, no weapons (e.g., pocket knives) or 

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

the building. We recommend 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 
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Building, Room 3334, 1301 Constitution Ave., NW, Washington, DC. 

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

Monday through Friday, excluding holidays. The telephone number 

for the Public Reading Room is (202) 566-1744, and the telephone 

number for the EPA Docket Center is (202) 566-1742.

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

Incineration Group, Sector Policies and Programs Division 

(E143-05), Environmental Protection Agency, Research Triangle 

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.

ANSI American National Standards Institute

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

CEMS Continuous emissions monitoring system

CFCs Chlorofluorocarbons

CISWI Commercial Industrial Solid Waste Incinerators

CFR Code of Federal Regulations

CHP Combined heat and power

CO2 Carbon dioxide

CO2 Carbon dioxide equivalent

CSAPR Cross-state Air Pollution Rule

DOE Department of Energy

EE Energy efficiency

EGs Emission Guidelines

EGU Electric generating unit

EIA Energy Information Administration

EJ Environmental justice
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EM&V Evaluation, measurement, and verification

EPA Environmental Protection Agency

EO Executive Order

FERC Federal Energy Regulatory Commission

FIP Federal implementation plan

FR Federal Register

GHG Greenhouse gas

GHGRP Greenhouse Gas Reporting Program

GJ/h Gigajoule per hour

HAP Hazardous air pollutants

ICR Information collection request

IGCC Integrated gasification combined cycle unit

IPM Integrated Planning Model

IPCC Intergovernmental Panel on Climate Change

ISO/RTO Independent System Operator/Regional Transmission 

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

NERC North American Electric Reliability Corporation

NSPS New source performance standards

NSR New Source Review

NTTAA National Technology Transfer and Advancement Act

NOX Nitrogen oxides

OAP Office of Atmospheric Programs

OAQPS Office of Air Quality Planning and Standards

PRA Paperwork Reduction Act

PUC Public Utility Commission

RE Renewable energy

REC Renewable Energy Certificate

RFA Regulatory Flexibility Act

RGGI Regional Greenhouse Gas Initiative

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
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TTN Technology Transfer Network

UMRA Unfunded Mandates Reform Act

UNFCCC United Nations Framework Convention on Climate 

Change

U.S. United States

WWW World 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
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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

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
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E. Treatment of States Entering or Exiting the Trading Program

F. Allowance Tracking, Compliance Operations, and Penalties

1. Designated Representatives and Alternate Designated 

Representatives

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
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G. The EPA’s Continued Engagement

X. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and 

Executive Order 13563: Improving Regulation and Regulatory 

Review

B. Paperwork Reduction Act (PRA)

C. Regulatory Flexibility Act (RFA)

D. Unfunded Mandates Reform Act (UMRA)

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 CAA, Congress created a partnership between the EPA

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

establishes emission performance levels based on its 

determination of the BSER for existing sources of air pollution 

and provides guidelines for state plans to apply standards of 

performance to their sources that meet the BSER level of 

performance. The EPA promulgated EGs under CAA section 111(d) 

which set source-level CO2 emission performance rates for the 

EGUs at certain large fossil fuel-fired power plants (“affected 

EGUs”). States then apply these EGs to their sources in 

developing state plans to achieve these emission performance 
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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. 

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 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 
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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 GHG pollutant, from 

certain 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 promulgate a final federal plan for only the 

affected EGUs in states that the EPA determines did not submit 

an approvable plan. 

At the same time, these two proposed options offer states 

model trading rules that the states can follow in developing 

their own plans in order to capitalize on the flexibility built 

into the final EGs. Thus, this document 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 
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potential use by any state. The regulatory text of each federal 

plan and 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 finalize 

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

state does not submit an approvable plan by the deadlines 

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

the state has failed to submit a plan, or disapproving a 

submitted plan because it does not meet the requirements of the 

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

for their sources rather than undertake the development of a 

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

proposed rule, a federal plan promulgated for a particular state 

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

 

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

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

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

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

discussed in the following section of this preamble. We invite 

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

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

approach.

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

opportunity as possible to set their own course for carrying out 

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

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

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

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

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

administrative aspects of the federal plan in order to become 

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

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

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

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

proposes to allow states to submit partial state plans to 

replace the federal plan allowance-distribution provisions with 

their own allowance-distribution provisions, similar to the 

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

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 serve as a mechanism to facilitate larger trading markets 

since consistency with the federal plan allows trading across 

both the state and federal programs. The EPA expects a larger 

 

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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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 

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

submit a tribal plan to implement CAA programs, including 

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

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

not subject to the deadlines applicable to state action under 

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

these EGUs could go unregulated. Therefore, as discussed in 

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

appropriate finding. 

This document 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 
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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. Finally, the agency 

proposes to clarify and request comment on an interpretive issue 

raised in the Clean Power Plan proposal regarding whether a 

reconstruction or modification that is subject to a CAA section 

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

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

VII of this preamble. The agency intends to finalize these 

changes earlier than the finalization of the model trading 

rules.

In proposing a federal plan, the EPA considered a variety 

of potential impacts that its action might have on the 

environment, on businesses, particularly in the energy sector, 

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

extensive consideration to impacts on vulnerable communities, 

particularly low-income communities, communities of color, and 
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indigenous communities. These considerations are discussed in 

sections III, VIII, IX, and X of this preamble.

The agency convened a Small Business Advocacy Review Panel 

under the Regulatory Flexibility Act and has completed an 

Initial Regulatory Flexibility Analysis (IRFA). Various 

recommendations from the Panel are found reflected throughout 

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

explains how it has conducted or intends to conduct all other 

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

proposed action. The EPA also explains in this document 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.G 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 that 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., ratebased 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-,
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regional-, or national level. As a result, compliance strategies 

can mirror, or be integrated with, the ongoing operations of the 

current electricity grid as it continues to serve its primary 

critical function of ensuring an uninterrupted supply of 

affordable and reliable electricity. This flexibility is 

especially valuable whenever the need to address specific 

reliability concerns arises. It allows owners and operators of 

reliability-critical EGUs to continue to meet their compliance 

obligations while operating to maintain electric reliability.

The EPA outlined and initiated the Clean Energy Incentive 

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

EGs). The program is designed to incentivize investment in 

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

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

demand during 2020 and/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
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approaches, the EPA has incorporated components to address the 

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

trading program could incentivize shifting generation from 

existing units in ways that would result in more CO2 emissions 

than would otherwise be expected, or that undermine the purpose 

of the CAA section 111(d) program. 

We considered whether compliance choices under a federal 

plan could lead to an unintended concentration of other air 

pollutants in certain overburdened communities, particularly 

low-income communities and communities of color. As discussed 

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

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

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

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

action could trigger an obligation to consult with other 

agencies responsible for implementing the Endangered Species 

Act, and propose to conclude that it will not.

In the final emission guidelines, the EPA emphasized the 

importance of state actions to ensure that in developing their 

respective compliance plans the states addressed the concerns 

and priorities of vulnerable communities. In the process of 

developing a final federal plan, the EPA will also take actions 

to address those concerns as well. In addition to the public 
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hearings that the EPA will be holding for all members of the 

American public on this proposed rulemaking, we will also be 

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

regions on this proposed rulemaking for communities. The goal of 

these outreach activities is to provide communities with the 

information they need to understand how the proposed rulemaking 

will potentially impact their respective communities. At the 

same time, this information will be useful in helping 

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

with their states during the state plan development process. We 

will also be providing other outreach and support activities for 

vulnerable communities, which are outlined in the community and 

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

this preamble.

B. Organization and Approach for this Proposed Rule

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

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

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

approaches to a federal plan to implement the Clean Power Plan 

EGs — a rate-based trading approach and a mass-based trading 

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 
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substantial flexibility in meeting their compliance obligations. 

For this reason, among others, these proposed approaches also 

serve as two proposed model trading rules that states may adopt 

or tailor in designing their own plans.

The EGs provide that states have until September 6, 2016 

(or upon making an initial submittal, until September 6, 2018) 

to submit state plans, and the EPA does not intend to finalize

and implement the federal plan for any states prior to the 

agency’s action of determining a failure to submit a state plan 

or disapproving a state plan. At the same time, in order to 

support states’ consideration of adoption of one of the model 

trading rules as an approvable state plan, the agency intends to 

finalize either or both model rule options presented in this

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

submittals.

The EPA currently intends to finalize a single approach —

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

promulgated federal plans for particular states in order to 

enhance the consistency of the federal trading program, achieve 

economies of scale through a single, broad trading program, 

ensure efficient administration of the program, and simplify 

compliance options for affected EGUs. The EPA recognizes that 

the mass-based trading approach would be more straightforward to 

implement compared to the rate-based trading approach, both for 
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industry and for the implementing agency. The EPA, industry, and 

many state agencies have extensive knowledge of and experience 

with mass-based trading programs. The EPA has more than two 

decades of experience implementing 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. The EPA 

recognizes that it remains potentially possible to finalize a 

different approach to a federal plan in some circumstances, but 

believes that in general, and consistent with prior federal 

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

has the most 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 

BSER. In the EGs, the EPA has taken final action on the BSER for 

CO2 emissions from existing fossil fuel-fired EGUs. Any comments 
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on this proposed rule relating to the BSER, its stringency, 

rationale, or legal basis, will not be considered as, by 

definition, they will be beyond the scope of this action.3

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 

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 

this preamble.

2. The Mass-based Approach

 

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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The second approach to a federal plan that the EPA is 

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

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

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

the affected EGUs in each state, consistent with the mass goals 

established in the EGs. The EPA would initially distribute the

allowances within each state budget – less three proposed 

allowance set-asides – to the affected EGUs based on their 

historical 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 

three set-asides of allowances: (1) For a Clean Energy Incentive 

Program; (2) to support RE projects; and (3) to allocate 

allowances based on an updating measurement of affected-EGU 

generation. The EPA is also proposing that a jurisdiction may 

choose to replace the federal-plan allocation provisions with 

its own allowance allocation provisions. The mass-based approach 

is explained in greater detail in section V of this 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 
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parts of Indian country via a federal plan. This is discussed in 

section VI.D of this preamble. 

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

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

CFR part 60, subpart B. These 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 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 this

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?
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Regulated Entities. Existing fossil fuel-fired EGUs (or 

affected EGUs) covered by the final Clean Power Plan that are 

located in a state that does not have an EPA-approved state plan 

are potentially subject to this proposed action 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 apply as shown in 

Table 1 of this preamble: 

Table 1. Examples of Potentially Regulated Entitiesa

Category NAICS Code Examples of potentially regulated 

entities

Industry 221112a Fossil fuel electric power generating 

units

State/Local 

Government

221112b Fossil fuel electric power generating 

units owned by municipalities a Includes NAICS categories for source categories that own and operate 

electric power generating units (includes boilers and stationary combined 

cycle combustion turbines). 

b State or local government-owned and operated establishments are classified 

according to the activity in which they are engaged.

This table is not intended to be exhaustive, but rather 

provides a general guide for identifying entities likely to be 

affected by the proposed action. Whether an affected EGU is

affected by this action is described in the applicability 

criteria in 40 CFR 60.5845 and 60.5850 of subpart UUUU. 

Questions regarding the applicability of this action to a 

 

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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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 EGU is

identical to the definition in the final Clean Power Plan. 

Additionally, the applicability of the federal plan is 

consistent with the EGs, where an affected EGU subject to the 

federal plan is any steam generating unit (SGU), integrated 

gasification combined cycle unit (IGCC), or stationary 

combustion turbine (SCT) that was in operation or had commenced 

construction as of January 8, 2014,5 and that meets certain 

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

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

a SGU 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/h (250 MMBtu/h) 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 SCC, the unit must 

meet the definition of a combined cycle or combined heat and 

 

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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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/h), and historically have combusted more than 90 percent

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

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

Effective State Plan

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

authorizes the EPA to develop and implement a federal plan for 

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

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

federal plan has been put in place in a state, but is later 

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

become subject to the state plan as of the effective date 

specified in a Federal Register notice regarding the EPA’s 

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

to be submitted by the states that submit negative declarations. 

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

affected EGUs located in these states, the final federal plan 

 

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

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

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

facilities in each state. Recognizing the urgent need for 

actions to reduce GHG emissions, and in accordance with the 

Presidential Memorandum7, as well as the benefit of providing 

states with model trading rule options to consider as they 

prepare their state plans, the EPA is proposing this rulemaking 

concurrently with the Administrator’s signing and promulgation 

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

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

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 2 in section II.B of this 

preamble) to determine if approval occurred since publication of 

the most recent version of 40 CFR part 62.

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

Do not submit information that you consider to be CBI 

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

or deliver information identified as CBI to only the following 

 

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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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 

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.

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

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

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

docket, an electronic copy of the proposed action is available 

on the Internet 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 
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proposed action at 

http://www2.epa.gov/cleanpowerplan/regulatoryactions#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 August 3, 2015, the EPA finalized the Clean Power Plan 

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

UUUU) under authority of section 111 of the CAA (79 FR 34950). 

The Guidelines apply to existing fossil fuel-fired EGUs, i.e.,

those that were in operation or had commenced construction 

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

guidelines are required to submit to the EPA by September 6, 

2016, a state plan that implements the EGs. States may also make 

initial plan submittals in lieu of a complete state plan, in 

which case extensions will be granted until September 6, 2018

(40 CFR part 60, subpart UUUU).8 As discussed in section VI.D of 

this preamble, Indian Tribes may, but are not required to, 

 

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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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 

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

 

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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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 outside the scope for this proposed 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 EGs for existing EGUs. States with affected EGUs 

are to submit state plans or make initial submittals to the EPA 
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by September 6, 2016 pursuant 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 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 Clean Power Plan and framework 

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

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

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

law and that the state has necessary legal authority to 

implement and enforce the rule, and evidence that procedural 

requirements, including public participation under 40 CFR 60.23, 

have been met. 

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

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

incorporated by reference with a minimum of changes that would 

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

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

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

few if any adjustments. States may make changes to the model 

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

rule such as by expanding the scope of eligibility of projects 

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

may still approve the plan, but the EPA would conduct 

appropriate review of such provisions for consistency with the 

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

satisfaction that its alternative provisions are as stringent as 

the presumptively approvable approach described. We note here, 

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

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

for the federal plan is different than the scope of eligibility 

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

provisions in the regulatory text relevant to these other ERC 

resources is relevant only to the proposed model trading rule 

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

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

the model rule and only metered RE and applicable nuclear are 

applicable to the federal plan). 

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

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

independent notice-and-comment rulemaking process. Without 

prejudging the outcome of that process, the EPA recognizes that 

it may be able to approve or “conditionally approve” state plans 

that are substantially similar, but not identical to, the final
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model trading rules. Ultimately, state plans must meet the 

requirements of the EGs for approvability. Thus, a conditional

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

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

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

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

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

In accordance with the EGs, the process for review and 

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

model trading rules or otherwise, would occur once the states 

have made their submissions by September 6, 2016. As provided in 

the EGs, states have the option of not submitting a full state 

plan, but rather making an initial submittal, in order to obtain 

an extension of 2 years before submitting a full state plan for 

EPA approval. It could be beneficial for coordination purposes 

if a state that is interested in adopting one of the model 

trading rules but intends to make an initial submittal next year

were to indicate which model 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 
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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 while also, for 

the past several decades, maintaining compliance with air 

pollution control programs. Since, as a practical matter under 

both the EGs and any federal plan, emissions reductions must 

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

program would be particularly effective in allowing EGUs to 

operate in a way that achieves pollution control without 

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

critical functions that 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 
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comments submitted on the proposed EGs that there is a strong 

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

the deadline for state submittals under the EGs. According to 

these stakeholders, model rules can provide predictability for 

planning purposes, both among states and affected EGUs. In 

addition, some states have indicated that they may prefer to 

rely on a federal plan, either temporarily or permanently,

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

model trading rule addresses these policy interests.

The approach of proposing model trading rules that are 

identical in all key respects to proposed federal plans that may 

be promulgated later, is consistent with prior CAA section 

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

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

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

respects with the Federal NOx Budget Trading Program at 40 CFR 

part 97 (65 FR 2674; Jan. 18, 2000). And the 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 

 

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.
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finalized in separate parts of the 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 by crossreference, along with any modifications or adjustments that may 

be appropriate at the time of actual promulgation of a federal 

plan.

Table 2. 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

 

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

aspects of the proposed subpart relevant to states as part of the model 

trading rule are not applicable 
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Region Regional contact Phone

States and 

protectorates

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, 

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 EGs, state plans 
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will be due on September 6, 2016, but states are also allowed to 

seek a 2-year extension for a final plan submittal, upon a 

satisfactory initial plan submittal by the same deadline. See 40 

CFR 60.5755, 60.5760(b). If a state does not submit a final 

state plan or initial plan submittal,13 or if either a final 

state plan or an initial plan submittal does not meet the 

requirements of the EG, the agency will take the appropriate 

steps to finalize and implement a federal plan for 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

 

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

both of which also constitute proposed model trading rules that 

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

currently intends to finalize one or both of the model trading 

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

soon as possible to help inform their state plan development 

efforts prior to the initial submittal deadline of September 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 

 

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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part. The EPA invites comments on this staged approach to 

finalizing one or more model trading rules on the one hand 

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

federal plans on the other (which we currently intend to do 

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

plans).

In this action, the EPA is also proposing enhancements to 

the process for agency action on state submittals and 

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

more detailed discussion of these changes, see section VII of 

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

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

finalize these changes on a timeline earlier than both a model 

trading rule and the federal plan. 

Under the framework regulations and the final EGs, at 40 

CFR 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 12 months from the date of a state's submission to 

approve or disapprove that state’s plan. The EPA will have 12 

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 6 months from the date of a state’s submission to 

notify a state that its submittal does not meet completeness 
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criteria and constitutes a failure to submit a plan. In the case 

of initial submittals under 60.5765, the EPA will have 60 days 

from September 6, 2016 to notify a state that its initial

submittal does not meet the requirements of 60.5760(a). As with 

state plans, the EPA will have 12 months to promulgate a federal 

plan from the date of its finding that a state failed to submit 

a complete and approvable initial submittal. (Formally, such a

finding would be that the state failed to submit a state plan.)

The timeframes stated in the previous paragraph reflect the 

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

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

a final federal plan for a state immediately upon making a 

finding of failure to submit a 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 FIP “at any time” within the 

2-year limit of CAA section 110(c) “that begins the moment EPA 

determines a SIP to be inadequate.” EME Homer City v. EPA, 134 

S. Ct. 1584, 1601 (2014). “EPA is not obliged to wait two years 

or postpone its action even a single day . . . .” Id. It is 

essential to implement plans for the control of emissions of CO2
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expeditiously and avoid unnecessary delay. Among other reasons, 

this will provide affected EGUs regulatory certainty and will 

assist the regulated entities as well as those authorities with 

responsibility for ensuring grid reliability to have as much 

time as possible to plan for the 2022 compliance start date set 

in the EGs. Thus, it is reasonable to propose this federal plan

now so that federal plans will be ready to be promulgated 

quickly in cases where states have failed to submit a plan or 

their plans are found unsatisfactory. 

It is the agency’s intention to promulgate federal plans 

promptly for states who do not submit plans or initial

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 

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 
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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 document, 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 statespecific subparts of part 62 and would be ministerial in nature. 

It would likely provide that the affected EGUs in each such 

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

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

finalized), along with any applicable modifications or 

adjustments as may be necessary, either based on new information 

or in response to comments regarding the application of the 

federal plan to that particular state. This text may appear

 

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

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

E. Use of the Model Trading Rule as a Backstop

As discussed in the final EGs, 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 sections VIII.C.3.b and 

VIII.C.6.c of the final EGs. To summarize those provisions, 

without reopening them for comment, the federally enforceable 

backstop must fully achieve the CO2 emission performance rates or 

the state’s interim and final CO2 emission goal if the state plan 

fails to achieve the intended level of CO2 emission performance. 

The state plan submittal must identify the federally enforceable 

emission standards for affected EGUs that would be used in the 

 

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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backstop, demonstrate that those emission standards meet the 

requirements that apply in the context of an emission standards 

approach, identify a schedule and trigger for implementation of 

the backstop that is consistent with the requirements in the 

EGs, and identify all necessary state administrative and 

technical procedures for implementing the backstop (e.g., how 

and when the state would notify affected EGUs that the backstop 

has been triggered). In addition, the backstop emission 

standards must make up for any shortfall in CO2 emission 

performance during a prior plan performance period that led to 

triggering of the backstop.

The EGs explicitly recognized that the backstop emission 

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

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

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

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

a minimum of changes necessary to make the rule appropriate for 

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

Instances of this approach are throughout the proposed rule text 

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

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

measures” plan.

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

model trading rules proposed in this action is the requirement 
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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 where an emission standard is imposed 

and federally enforceable on the affected EGUs: in the ratebased approach the emissions standard is an allowable rate of 

emissions; in the mass-based approach the emission standard is 

the requirement to hold allowances equal to reported emissions. 

The EPA may also handle the administration of the trading 

program for states utilizing the model trading rule. However, 

even though the backstop may take the form of an EPA-
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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 

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), 

 

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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and section 304, 42 U.S.C. 7604. This means that the 

Administrator has the ability to enforce against violations and 

secure appropriate corrective actions pursuant to CAA sections 

113(a)–(h), and states and other third parties maintain the 

ability to enforce against violations and secure appropriate 

corrective actions pursuant to CAA section 304.

III. Federal Plan Structure to Achieve Reductions

A. Overview

1. Interactions with State Plans and scope of trading

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

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

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

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

compliance instruments with affected EGUs in any other state 

covered by a federal plan or a state plan meeting the conditions 

for linkage to the federal plan. In the proposed mass-based 

federal-plan trading program, this would mean that affected EGUs

in a state covered by the federal plan or a state meeting the 

conditions for linkage to the federal 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 
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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 massbased 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 affected EGUs in states covered by the proposed federal 

plans and affected EGUs in states covered by state plans 

(referred to below as “linking” states, or “linkages”) under the 

following conditions, which are discussed further below the 

list:

• The state plan must be approved.

• The state plan must implement the same type of trading 

program as the federal plan trading program in order to be 

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

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

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

programs only.
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• The state plan must use the identical compliance instrument 

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

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

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

(we are also requesting comment on expanding this to 

include a state plan that uses an EPA-designated tracking 

system that is interoperable with an EPA-administered 

system, as detailed below).

The EPA proposes that interstate ERC trading could occur 

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

trading federal plan to affected EGUs in states with approved 

rate-based trading state plans meeting the proposed conditions

for linkages (including the conditions for being “ready-forinterstate-trading” that were finalized in the EG), and 2) from 

affected EGUs in such state-plan-covered states to affected EGUs 

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

expanding the scope of interstate trading to include linking 

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

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

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

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

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

state plan meeting the proposed conditions for linkages and that 

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

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

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

comment on allowing a state that has an approved mass-based 

trading state plan meeting the proposed conditions for linkages 

and that uses an EPA-designated allowance tracking system to 

register with the EPA, and after registration, to link with 

states covered by the mass-based 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 (see Clean Power 

Plan EGs, section VIII). In this proposed rule, the proposed 

approach to link from the mass-based trading federal plan to 

 

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

noted.
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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 opportunities for cost-effective implementation of 

reductions compared to trading limited to a smaller region. The 

proposed approach to interstate trading is intended to strike a 

reasonable balance between providing the opportunity for a wide 

interstate trading system while maintaining the integrity of the 

linked programs. The agency requests comment on the proposed 

approach to interstate trading linkages in the federal plans.

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

the allowance market would be competitive. The opportunities for 

interstate trading detailed above would reduce any potential for 

firms to exercise market power in the ERC market or allowance 

market. The EPA requests comment on this expectation of a 

competitive ERC market and a competitive allowance market, and 

comment on potential program design choices that could address 

any identified market power concern. The EPA intends to provide 

information to the market and the public, consistent with other 

trading programs that the agency administers, as detailed in 

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

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.
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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 

guidelines, restricts 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 rate-based state have contracted 

for the delivery of the RE generation that occurs in a massbased state to meet load in a rate-based state. As part of this 

federal plan, we are proposing that this can be demonstrated

through the provision of a power delivery contract or power 

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

contracts for the supply of the MWhs in question and providing

documentation that the electricity was treated as comparable to 

a generation resource used to serve regional load that included 

the rate-based state. This demonstration must be included as 
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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 associated with that contractual arrangement with the massbased RE provider. The EPA requests comment on this approach. It 

should also be noted that we are proposing that under the 

proposed mass-based approach, if RE located in a mass-based 

state receives mass-based set-aside allowances for any 

generation, that generation is not eligible to be issued ERCs in 

a rate-based state.

The EPA requests comment on the proposed treatment of 

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

plan approach, and as part of the corresponding proposed model 

rules. 

3. Provisions to Encourage Early Action

The EPA outlined and initiated the Clean Energy Incentive

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

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

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

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

These RE projects must commence construction, and these EE 

projects must commence implementation after the date of 
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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 

U.S. Inventory of Greenhouse Gas Emissions and Sinks19 (the U.S. 

GHG Inventory). 

 

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
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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.

 

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

C. Affected EGUs

For the Clean Power Plan and this federal plan, an affected 

EGU is any SGU, IGCC, or stationary combustion turbine that was 

in operation or had commenced construction as of January 8, 

2014,28 and that meets the following criteria, which differ 

depending on the type of unit. To be an affected EGU, such a 

unit, if it is SGU 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 

 

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

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

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

on the date that the EPA proposes action on such sources. January 8, 2014 is 

the date the proposed GHG standards of performance for new fossil fuel-fired 

EGUs were published in the Federal Register (79 FR 1430).

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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MMBtu/h) heat input of fossil fuel (either alone or in 

combination with any other fuel). If such a unit is a SCT, the 

unit must meet the definition of a combined cycle or CHP 

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). 

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 SCT 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. CHP 

combustion turbine means any SCT which recovers heat from the 

combustion turbine engine exhaust gases to heat water or another 

medium, generates steam for useful purposes other than 

exclusively for additional electric generation, or directly uses 

the heat in the exhaust gases for a useful purpose.

We note that certain affected EGUs are exempt from 

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

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

subject to subpart 40 CFR part 60, subpart TTTT as a result of 
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commencing modification or reconstruction; (2) are SGUs or IGCC 

units that are currently and always have been subject to a 

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

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

that are capable of combusting 50 percent or more non-fossil 

fuel) that have historically limited the use of fossil fuels to 

10 percent or less of the annual capacity factor or are subject 

to a federally enforceable permit limiting fossil fuel use to 10 

percent or less of the annual capacity factor; (4) are 

stationary combustion turbines that are not capable of 

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

pipeline); (5) are CHP units that are subject to a federally 

enforceable permit limiting, or have historically limited, 

annual net electric sales to a utility power distribution system 

to the product of the design efficiency and the potential 

electric output or 219,000 MWh (whichever is greater) or less; 

(6) serve a generator along with other SGU(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 SGU, 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 60.29

The EPA is also taking comment on an alternative compliance 

pathway that could be available to units under a mass based 

approach. The ways that the approach could be implemented are 

further outlined in the Alternative Compliance Pathway for Units 

that Agree to Retire Before a Certain Date TSD. Under this 

approach, two basic requirements would need to be met. The first 

is that the unit would have to take a commitment that it would 

retire on a date on or before December 31, 2029. The second is 

that the unit would have to demonstrate that it will take an 

enforceable emission limitation that would assure that the 

overall state emission goal is met. The TSD explores ways that 

this approach could be implemented, including ways that the 

enforceable emission limitation could be calculated and 

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 

 

29 We had proposed in the CPP EGs that affected EGUs were those existing 

source fossil fuel-fired EGUs that met the applicability criteria for 

coverage under the final GHG standards for new fossil fuel-fired EGUs being 

promulgated under CAA section 111(b). However, we are finalizing in the EGs 

that states need not include certain units that would otherwise meet the CAA 

section 111(b) applicability in this CAA section 111(d) EGs. These include 

simple cycle turbines, certain non-fossil units, and certain CHP units. The 

final CAA section 111(b) standards include applicability criteria for simple 

cycle combustion turbines, for reasons relating to implementation and 

minimizing emissions from all future combustion turbines.
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comment on whether and how such an approach could be included 

under a rate-based approach. 

The applicability of this proposed federal plan follows the 

same applicability criteria as the final EGs. The rationale for 

these criteria is provided in section IV.D of the Clean Power 

Plan. We are not reopening the criteria or rationale here. 

In the federal plan Affected EGU Technical Support Document 

(TSD), the EPA lists all applicable affected EGUs according to 

our records from the National Electric Energy Data System 

(NEEDS), Energy Information Administration (EIA), and comments 

from the CPP. In this TSD, each affected EGU is assigned its 

proposed applicable standards if a federal plan were to be 

promulgated for that affected EGU at any time. The EPA requests 

comments and updates to this list of affected units. Section 

VI.C of the final 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, 

2029). The Final Period would run from beginning of calendar 
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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.30

The EPA recognizes that the compliance periods provided for 

in this rulemaking are longer than those historically and 

typically specified in CAA rulemakings. As reflected in longstanding CAA precedent, “[t]he time over which [the compliance 

standards] extend should be as short term as possible and should 

 

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

approach. 
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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 

trading approaches, while also maintaining the stringency 
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required by the final EGs. A number of aspects of the rate-based 

and mass-based programs would assist with this, including 

allocation methods or rules, mechanisms to place allowances or 

credits into the market relatively early, requirements for 

public transparency of information related to allowance, or 

credit issuance, tracking, transfers and holdings. The EPA 

solicits comment on other approaches to ensure market liquidity 

while continuing to meet the stringency of the final EGs.

E. Addressing Reliability Concerns 

The proposed federal plan has been designed to ensure that, 

to the greatest extent possible, implementation would not 

interfere with the power sector’s ability to maintain electric 

reliability.31 Like the EGs, the federal plan provides a long 

planning horizon and implementation period. In addition the 

federal plan allows affected EGUs to obtain tradable allowances 

and credits to meet obligations which assures that reliability 

can be maintained without disruption to the electricity system.

There are many features of the electricity system that 

ensure that electric system reliability will be maintained. For 

example, in the Energy Policy Act of 2005, Congress added a 

 

31 The EPA evaluated certain aspects of electric reliability in the context of 

modeling projections for the final Clean Power Plan, and that evaluation is 

described in the “Resource Adequacy and Reliability Analysis TSD” for that 

rulemaking, a copy of which is also included in the docket for this 

rulemaking.
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section to the Federal Power Act to make reliability standards 

mandatory and enforceable by the 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 

multidimensional, comprehensive and sophisticated. Under this 
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approach, planning authorities plan the system to assure the 

availability of sufficient generation, transmission, and 

distribution capacity to meet system needs in a way that 

minimizes the likelihood of equipment failure.32 Long-term system 

planning happens at both the local and regional levels with all 

segments of the electric system needing to operate together in 

an efficient and reliable manner. In the short-term, electric 

system operators operate the system within safe operating 

margins and work to restore the system quickly if a disruption 

occurs.33 Mandatory reliability standards apply to how the bulk 

electric system is planned and operated. For example, 

transmission operators and balancing authorities have to 

develop, maintain and implement a set of plans to mitigate 

operating emergencies.34

The EPA’s approach in this proposed federal plan builds on 

the foundation provided in the EG’s determination of BSER to 

ensure that the final federal plan, like the final EG, does not 

interfere with the industry’s ability to maintain reliability of 

the nation’s electricity supply. First, the federal plan, like 

 

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

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

Press, at 160 (2010).

33 Id.

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

available at http://www.nerc.net/standardsreports/standardssummary.aspx.
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the EG, provides more than 6 years before reductions are 

required and an 8-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 CPP EGs, the EPA laid out the availability of

a reliability safety valve that could be used if an 

unanticipated catastrophic emergency caused a conflict between 

maintenance of electric reliability and inflexible requirements 

that a state plan might impose on an affected EGU or EGUs. Under 

the federal plan, inflexible requirements are not imposed on 

specific plants. Rather as explained earlier, the very nature of 

the federal plan, in which affected EGUs can obtain allowances 
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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 EGs 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 EGs, the EPA suggested that to ensure that emission 

reductions are realized, it is important that construction, 

operations and other skilled work undertaken pursuant to state 

plans is performed to specifications, and is effective, safe, 

and timely. The EPA asks for comments as to whether the federal 

plan should encourage EGUs to ask for a demonstration that the 

work undertaken under a federal plan is performed by a 

proficient workforce. A good way to ensure such a workforce is 

to require that workers have been certified by: (1) An 

apprenticeship program that is registered with the U.S. DOL, 

Office of Apprenticeship or a state apprenticeship program 

approved by the DOL; (2) a skill certification aligned with the 

U.S. DOE Better Building Workforce Guidelines and validated by a 

third party accrediting body recognized by DOE; or (3) other 

skill certification validated by a third party accrediting body.
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G. Remaining Useful Lives and Potential for “Stranded Assets”

Section 111(d)(2) of the CAA provides, “In promulgating a 

standard of performance under a plan prescribed under this 

paragraph, the Administrator shall take into consideration, 

among other factors, remaining useful lives of the sources in 

the category of sources to which such standard applies.” 42 

U.S.C. 7411(d)(2). This language tracks similar language in CAA

section 111(d)(1) with respect to state plans. In the final EGs, 

we explained how the Guidelines permit states in applying a 

standard of performance in their state plans to consider the 

remaining useful life of a facility. We determined that it was 

appropriate to specify that the general variance provisions in 

40 CFR 60.24(f) should not apply to the class of affected 

facilities covered by these Guidelines. We concluded that 

facility-specific factors and in particular, remaining useful 

life, do not justify a state making further adjustments to the 

performance rates or aggregate emission goal that the Guidelines 

define for affected EGUs in a state and that must be achieved by 

the state plan. 

Because the Guidelines do not allow for states to deviate 

from state goals based on remaining useful life, the EPA does 

not believe such goal adjustments are necessary or appropriate 

in the federal plan either. Nonetheless, this does not obviate 

the requirement that the EPA itself, in the design of its 
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federal plan, consider, among other factors, the remaining 

useful lives of the affected facilities. The agency therefore 

proposes the following analysis of this factor.35

Congress added the “remaining useful lives” factor to CAA 

section 111(d)(2) in the 1977 CAA Amendments. Congress did not 

provide in the statute any direction on how or to what degree 

“remaining useful lives” of facilities subject to a section 

111(d) federal plan is to be considered. As discussed in the 

preamble to the final EGs, Congress’ intent in enacting the 

provision was to allow for older facilties with short remaining 

useful lives to not be required to install capital-intensive 

pollution control devices to meet emission standards that would 

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 

 

35 We note that the preamble and supporting materials for the EGs discuss a 

related concern raised by some stakeholders, which is whether the EGs could 

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

explained there, we believe this concern is distinct from the “remaining 

useful lives” factor in CAA section 111(d)(1), and for the same reasons, 

believe it is distinct from the factor Congress directed the agency to 

consider in CAA section 111(d)(2). Nonetheless, we undertook analysis in the 

final EGs of whether and to what extent there may be a “stranded asset” 

concern. See memorandum to Clean Power Plan Docket EPA-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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available to meet emission limits were pollution control 

technology.” H. Report 94-1175, at 159 (1976) (emphasis added). 

This language is probative of the fact that Congress viewed 

“remaining useful lives” as a consideration for facilities with 

relatively little remaining useful life. We are confident the 

proposed federal plan will not force costly pollution control 

investments at older plants with short remaining useful lives.

Further, the statute provides that this factor is one 

“among other factors” that the agency is to consider in 

promulgating a standard of performance. Congress provided no 

guidance in the statute as to what those other factors could be. 

The inclusion of unspecified factors that the agency may 

determine for itself to consider, along with the use of the term 

“consider,” highlights that Congress intended to give the agency 

a substantial degree of discretion in determining how the 

“remaining useful lives” factor is considered. The statute does 

not require, and Congress did not intend, that this 

consideration mandate the agency to prevent all premature 

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 
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preconstruction requirements of the PSD/non-attainment new 

source review (NSR) program, see CAA section 165(a). And in CAA 

section 169A related to visibility impairment in federal class I 

areas, Congress excluded from applicability units that began

operation before August 7, 1962. 42 U.S.C. 7491(b)(2)(A). In CAA

section 111(d) Congress did not set any such specific criteria. 

Rather it directed the agency to “consider” the remaining useful 

lives of facilities, among other factors.

This view also accords with past agency practice in 

implementing a similar provision. In the 1977 Amendments, 

Congress listed “remaining useful life” as a factor for 

consideration in the visibility program under section 169A. 42 

USC 7491. The “remaining useful life of the source” is one of 

several enumerated factors that the state or the EPA is to 

consider in determining the best available retrofit technology 

(BART) for a particular source. Consistent with congressional 

purpose, the EPA has implemented this factor in the regional 

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 
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the time period for amortizing costs, you should use 

this shorter time period in your cost calculation.

40 CFR part 51, appendix Y, section IV.D.4.k. In the 

agency’s view, this approach to “remaining useful life” aligns 

with congressional intent and informs our view of how the 

“remaining useful lives” factor should be considered under this 

CAA section 111(d) federal plan. The key consideration is 

whether the time period associated with amortizable costs of 

compliance will exceed the remaining useful lives of the sources

in question.

Consistent with legislative intent and past agency 

practice, we propose that the federal Plan adequately considers

”remaining useful lives” of affected EGUs by providing for 

trading and other flexibilities authorized in the EGs. To 

summarize, these include: relatively long periods for affected 

EGUs to come into compliance, the ability to credit early 

action, the use of emissions trading, the use of multi-year 

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 over-performance of some 

affected EGUs, and allow others to simply acquire credits or 

allowances to comply with their emission standard, thereby 
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avoiding the need for installation of costly pollution controls 

at sources with a short remaining life.

Thus, the proposed federal plan is designed in such a way 

that it adequately, and inherently, takes into account the 

remaining useful lives of affected EGUs. It provides substantial 

compliance flexibility, including means of avoiding the need to 

make extensive capital investments in control technologies that 

could not be recouped during the remaining useful lives of a 

facility.36 The design of the federal plan as a form of emission 

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 

 

36 Because we believe that this is the case for all facilities through the 

basic design of the federal plan, we also can confirm, in line with the EGs, 

that the availability of variances from the emission standards is unnecessary 

in the federal plan. Under the general framework regulations, 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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effect, under a trading program with repeating compliance 

periods, a facility with a short remaining useful life has a 

total outlay that is proportionately smaller than a facility 

with a long remaining useful life, simply because the first 

facility would need to comply for fewer compliance periods and 

would need proportionately fewer ERCs or allowances than the 

second facility. Buying ERCs or allowances as a compliance 

method could avoid excessive up-front capital expenditures that 

might be unreasonable for facilities with short remaining useful 

lives, and therefore addresses the consideration of “remaining 

useful lives.” Buying ERCs or allowances as a compliance method 

also would reduce the potential for stranded assets.

In addition, the timing of the federal plan limits the 

immediate costs of compliance, particularly for facilities that 

have useful lives ending before 2022, but also for facilities 

that have useful lives ending before 2030. There are no 

compliance obligations for affected EGUs under this federal plan 

until 2022, when the first compliance period begins. At that 

point, the agency is following the glide path provided for in 

the EGs, which begins with relatively higher emission targets 

that will slowly strenghten over the interim performance period 

from 2022-2029 through three multi-year compliance periods. The 

final, most stringent, compliance obligation does not begin 

until 2030.
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Further, unlike state plans that can be more stringent 

under CAA section 116, the federal plan is no more stringent 

than the EGs, and, as explained in the EGs, the Guidelines 

reflect a reasonable, rather than a maximum possible, 

implementation level for each building block in order to 

establish overall goals that are achievable. As discussed in the 

EG , the BSER determined an average level of emissions 

achievable by groups of EGUs, rather than for an individual EGU.

In considering the remaining useful lives of facilities under a 

federal plan, the EPA believes this approach to setting the 

emission standards, coupled with the ability to trade, 

adequately accounts for remaining useful lives of facilities. In 

essence, it allows the facilities to comply with the federal 

plan through the purchase or acquisition of ERCs or allowances, 

and to avoid the need to make costly investments in control 

technology for plants that have short remaining useful lives.37

For these reasons, the federal plan adequately considers 

“remaining useful lives.” We invite comment on our consideration 

of facilities’ “remaining useful lives” in the federal plan.

H. Implications for Other EPA Programs and Rules

1. Title V Permitting

 

37 In addition, the ability to generate ERCs for sale or to sell unneeded 

emission allowances (depending on whether in a rate- or mass-based system) 

may give some affected EGUs an economic incentive to take measures to reduce 

emissions that otherwise would have been uneconomical.
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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 CAA and the regulations implementing title V, 40 

CFR parts 70 and 71.38 All major stationary sources of air 

pollution and certain other sources are required to apply for 

title V operating permits that include emission limitations and 

other conditions as necessary to assure compliance with 

applicable requirements of the CAA, including the requirements 

of an applicable CAA section 111(d) state plan or federal plan. 

CAA sections 502(a) and 504(a), 42 U.S.C. 7661a(a) and 7661c(a). 

The “applicable requirements” that must be addressed in title V 

permits are defined in the title V regulations, and include 

requirements under CAA section 111(d) (40 CFR 70.2 and 71.2 

(definition of “applicable requirement”)).

The EPA anticipates that, given the nature of the units 

covered by the proposed federal plan, most of the sources at 

which they are located are already or will be subject to title V 

 

38 Part 70 addresses requirements for title V programs implemented by state, 

local, and tribal governments, and part 71 governs the title V program 

implemented by the EPA or delegate agencies in areas under federal 

jurisdiction, such as Indian country.
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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.

The EPA does not believe this approach is affected by the 

Supreme Court’s decision in Utility Air Regulatory Group v U.S. 

EPA, 134 S. Ct. 2427 (June 23, 2014). The Supreme Court held 

that the EPA may not treat GHGs as an air pollutant for purposes 

of determining whether a source is a major source required to 

obtain a title V operating permit. In accordance with that 

decision, the D.C. Circuit’s amended judgment on April 10, 2015 

vacated the title V regulations under review in that case (40 

CFR 70.12 and 71.13) to the extent that they require a 

stationary source to obtain a title V permit solely because the 

source emits or has the potential to emit GHGs above the 

applicable major source thresholds. The D.C. Circuit also 

directed the EPA to consider whether any further revisions to 

its regulations are appropriate in light of UARG v. EPA, and, if 
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so, to undertake to make such revisions. As the agency made 

clear in a memorandum to Regional Administrators last year, 

“While the EPA will no longer apply or enforce the requirement 

that a source obtain a title V permit solely because it emits or 

has the potential to emit GHGs above major source thresholds, 

the agency does not read the Supreme Court decision to affect 

other grounds on which a title V permit may be required or the 

applicable requirements that must be addressed in title V 

permits.”39 Accordingly, while the emission of GHGs alone cannot 

trigger the need for a title V permit under UARG, the EPA 

believes a final federal plan under CAA section 111(d) will 

create new “applicable requirements” in the form of an emission 

standard (either an emission rate or an allowance system) and 

related requirements for GHGs (here, CO2) on affected EGUs. See 

40 CFR 70.2, 71.2 (definition of “applicable requirement” 

includes “any standard or other requirement under section 111 of 

the Act, including section 111(d)”) (emphasis added). Thus, an 

affected EGU may be required to modify its existing title V 

permit, or obtain a new permit if it does not already have one, 

if it becomes subject to an emission standard for CO2under a CAA 

section 111(d) federal plan.

 

39 Memorandum from Janet McCabe, Acting Assistant Administrator, Office of Air 

and Radiation, and Cynthia Giles, Assistant Administrator, to Regional 

Administrators, Regions 1-10, at 5 (July 24, 2014).
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The title V permits program is structured to provide 

flexibility for market-based approaches, such as allowance 

trading programs under the federal plan, including flexibility 

to make changes under such programs without necessarily 

requiring a formal permit revision. For example, the title V 

regulations provide that a permit issued under title V shall 

include, for any “approved * * * emissions trading or other 

similar programs or processes” applicable to the source, a 

provision stating that no permit revision is required “for 

changes that are provided for in the permit.” 40 CFR 70.6(a)(8) 

and 71.6(a)(8). Consistent with this provision in the title V 

regulations, the proposed federal plan regulations include a 

provision stating that no permit revision shall be required for 

the allocation, holding, deduction, or transfer of allowances

once the requirements applicable to such allocations, holdings, 

deductions, or transfers of CO2 allowances are already 

incorporated in such permit. Consistent with title V 

regulations, this provision should be included in each title V 

permit for a covered source. As a result, allowances will be 

able to be traded (or allocated, held, or deducted) under the 

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 
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modification procedures for permit modifications “involving the 

use of economic incentives, marketable permits, emissions 

trading, and other similar approaches, to the extent that such 

minor permit modification procedures are explicitly provided for 

in an applicable implementation plan or in applicable 

requirements promulgated by EPA.” 40 CFR 70.7(e)(2)(i)(B) and 40 

CFR 71.7(e)(1)(i)(B). Therefore, the EPA is proposing that any 

changes that may be required to an operating permit with respect 

to a trading program under the federal plan may be made using 

the minor permit modification procedures of the title V rules. 

The EPA proposes that such changes may include the initial 

changes needed to the title V permit to establish the 

applicability of the trading program to the source, specify the 

covered units, and to include other permit terms that may be 

needed for implementation, including the general approach for 

monitoring and reporting. The minor permit modification 

procedures could also be used for any subsequent changes to 

permit terms that may be needed with respect to the trading 

program, although we expect such changes to be infrequent. As 

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 
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changes do not conflict with any existing terms of the permit. 

If a sources wishes to make a change that would go against any 

express term of the permit, the permit must be revised to allow 

such a change before the source begins operation of the change. 

Under the implementation strategy described above, the EPA 

believes it would be unlikely that any change in trading 

allowances would violate a term of a permit, but this principle 

is important to keep in mind when deciding if a minor permit 

modification is appropriate with respect to operating a trading 

program in the context of a title V permit.

The EPA believes that the approach to permitting 

requirements we are proposing here, which imposes no additional 

permitting requirements independent of title V and provides for 

the use of minor permit modification procedures, will streamline 

the process for sources already required to be permitted under 

title V and for permitting authorities. If there are any sources 

that would become newly subject to title V as a result of the 

requirements of this proposed federal plan, the initial title V 

permit that would be issued pursuant to 40 CFR 70.7(a) or 

71.7(a) would address the federal plan requirements, when 

finalized.

The EPA notes that the approach to title V permitting that 

is being proposed is somewhat similar to the approach adopted in 

the final CSAPR. See 76 FR 48299-30 (Aug. 8, 2011). The agency 
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recently issued guidance to assist permitting authorities and 

sources subject to CSAPR in incorporating CSAPR requirements 

into title V permits.40 The EPA invites comment on its proposed 

approach to permitting requirements for the federal plan, 

including whether it would be of use to develop guidance similar 

to the guidance developed for permitting under CSAPR. The EPA 

invites comment on its proposed approach to incorporating 

applicable requirements of the federal plan into title V permits 

and revising those requirements, including specifically seeking 

comment on whether all requirements should be eligible for 

incorporation into title V permits via minor modification 

procedures or if only a specified 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 NSR program is a preconstruction permitting program 

that requires major stationary sources of air pollution to 

 

40 Memorandum from Anna Marie Wood, Director, Air Quality Policy Division, 

Office of Air Quality Planning and Standards (OAQPS), and Reid P. Harvey, 

Director, Clean Air Markets Division, Office of Atmospheric Programs (OAP), 

to Regional Air Division Directors, 1-7, regarding Title V Permit Guidance 

and Template for the Cross-State Air Pollution Rule (May 13, 2015).
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obtain permits prior to beginning construction. The requirements 

of the NSR program apply both to new construction and to 

modifications of existing major sources. Generally, a source 

triggers these permitting requirements as a result of a 

modification when it undertakes a physical or operational change 

that results in a significant emission increase and a net 

emissions increase. NSR regulations define what constitutes a 

significant net emissions increase, and the concept is 

pollutant-specific. 

In the final EGs, 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 

federal plan may choose, as a means of compliance with either a 
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rate-based or mass-based approach, to undertake a physical or 

operational change to improve an affected EGU’s efficiency that 

results in a significant net emissions increase of a regulated 

NSR pollutant. This would trigger NSR. However, as with state 

plans, the EPA believes that these situations will be few.

After the proposal for the Clean Power Plan was published 

in June of 2014, the U.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 GHG 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 GHGs 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 SGU), cannot trigger 

NSR.

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 
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harmonizing or streamlining the permitting process for such 

sources that are consistent with judicial precedent. However, 

the EPA is not proposing any changes to the NSR program in this 

action, and the agency is not reopening or reconsidering any 

prior actions or determinations related to NSR in this action. 

Any comments related solely to the NSR program will be 

considered outside the scope of this proposed rule.3. 

Interactions with Other EPA Rules

Existing fossil fuel-fired EGUs, such as those covered in 

this proposal, are or will be potentially impacted by several 

other rules recently finalized or proposed by the EPA.41 These 

rules include the Mercury and Air Toxics Standards (MATS) (77 FR 

9304; Feb. 16, 2012);42 the CSAPR; Requirements for Cooling Water 

Intake Structures at Power Plants (79 FR 48300; Aug. 15, 2014); 

Disposal of Coal Combustion Residuals from Electric Utilities, 

issued on December 19, 2014; and the proposed Steam Electric 

Effluent Limitation Guidelines and Standards (78 FR 34432; June 

7, 2013). These rules are discussed in more detail in the final 

EGs along with steps the EPA is taking to enable compliance with 

 

41 We discuss other rulemakings solely for background purposes. The effort to 

coordinate rulemakings is not a defense to a violation of the CAA. Sources 

cannot defer compliance with existing requirements because of other upcoming 

regulations.

42 The Supreme Court recently reversed and remanded a D.C. Circuit Court of 

Appeals decision that had upheld the MATS rule. Mich. v. EPA, No. 14-46 (S. 

Ct. filed June 29, 2015). The Court did not vacate the rule, however, and it 

remains in effect.
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obligations under other power sector rules as efficiently as 

possible. We solicit comment on whether there are specific 

things the EPA can do in the design and implementation of the 

federal plan that further this objective.

I. Administrative Appeals Process

Under either a rate-based or mass-based trading program, 

the EPA anticipates that there may be situations in which 

individual parties are affected by decisions of the agency. For 

example, under a rate-based plan, a determination may be made 

that an eligibility application by an ERC provider is denied. 

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

may believe that its allowance allocation amount was 

miscalculated. Similar to prior trading programs, the agency 

believes it would be efficient and potentially avoid the need 

for recourse to litigation to provide an administrative appeals 

process. Therefore we are proposing, and requesting comment on, 

the use of the regulations for appeals procedures set forth in 

40 CFR part 78, to provide for the adjudication of certain 

disputes that may arise during the course of implementation of a 

federal plan under CAA section 111(d). We also propose to revise 

part 78 to accommodate such appeals. The part 78 procedures 

cover prior CAA emission trading programs and were specifically 

designed with these types of disputes in mind.
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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. 

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 affected 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 compliance period 

emissions data, including retroactive adjustment based on audit 

or other investigation. 
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In the case of a mass-based federal plan: decisions on an 

eligibilty application for set-aside allowances; decisions 

regarding the allocation of allowances to affected EGUs; 

decisions regarding the allocation of allowances from setasides; decisions on the transfer of allowances; decisions 

regarding the finalization of emissions data by affected EGUs 

during compliance periods; decisions making error corrections to 

information submitted by affected EGUs and other account 

holders; decisions that there has been excess emissions 

requiring a 2-for-1 allowance administrative compliance penalty; 

and decisions regarding the deduction or surrender of allowances 

for compliance from affected EGUs’ compliance accounts. 

We request comment on this list of actions for both types 

of approaches to the federal plan, and whether there are other 

decisions that may be made in the course of implementation of 

the federal plan that are party-specific that would be 

appropriate to list as appealable under part 78. We also take 

comment on whether it would be appropriate for the EPA to 

finalize an administrative appeals process that differs in any 

way from that offered under part 78, or in addition to that 

offered under part 78. If so, we request comment broadly on all 

aspects of the alternative or additional adminsitrative appeals 

process, including with respect to any structural, procedural, 

subtantive, and timing requirements it should include, who 
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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 standards 

of performance that achieve the emission performance levels by

determined by application of the BSER in the Clean Power Plan 

EGs. Both proposals are “emission standard” approaches as 

defined in the EGs, and the EPA is not proposing an approach 

like the “state measures” approach that is also available to 

states in the final EGs. The EPA has legal authority to 

establish either of the proposed trading systems as a federal 

plan under CAA section 111(d)(2). We discuss this topic briefly 

here and invite public comment. The EGs discussed the role of 

emissions trading in the BSER, see, e.g., section V.A of the 

preamble to the final EGs. The EPA regards this to be a separate 

issue and is not revisiting or reopening the discussion of the 

BSER or the role of trading in the BSER here. The EGs recognize 

and provide ample opportunity for states to establish standards 

of performance that allow the use of emissions trading or other 
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multi-unit compliance approaches. Here we discuss why an 

emissions trading program is a lawful and appropriate form of 

federal “implementation” of a “standard of performance” under 

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

discussion and the agency’s interpretation of its authority.

1. General Section 111(d)(2) Authority

Section 111(d)(2) provides as follows: 

The Administrator shall have the same authority—

(A) to prescribe a plan for a State in cases where the 

State fails to submit a satisfactory plan as he would 

have under section 7410(c) of this title [CAA section 

110(c)] in the case of failure to submit an 

implementation plan, and 

(B) to enforce the provisions of such plan in cases 

where the State fails to enforce them as he would have 

under sections 7413 and 7414 of this title [CAA 

sections 113 and 114] with respect to an 

implementation plan. 

In promulgating a standard of performance under a plan 

prescribed under this paragraph, the Administrator 

shall take into consideration, among other factors, 

the remaining useful lives of the sources in the 

category of sources to which such standard applies.

42 U.S.C. 7411(d)(2).43

The phrase “same authority to prescribe” indicates that 

Congress viewed the EPA’s authority to issue a federal plan for 

designated pollutants under CAA section 111(d) as, in some 

sense, co-extensive with its authority to issue a FIP for 

National Ambient Air Quality Standards (NAAQS) pollutants under 

 

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

discussed above in section III.G of this preamble.
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CAA section 110. This authority under CAA section 111, of 

course, must be understood in reference to the purpose of that 

section (i.e., to achieve emission reductions for designated 

pollutants from designated facilities), rather than in reference 

to the purpose of 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 CAA, 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 SIP. Thus, in 
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promulgating a FIP under CAA section 110, the EPA may exercise 

its own, independent regulatory authority in accordance with CAA 

section 110(c) and the CAA more broadly. When the EPA has 

promulgated a FIP, courts have not required explicit authority 

for specific measures: “We are inclined to construe Congress’

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 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 2-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.44 The scope of the 

 

44 We interpret the cross-reference to be to the currently enacted version of 

CAA section 110(c), rather than to a prior version. As discussed in section 

VII of this preamble, below, the current version of CAA section 110, 

including subsection (c), reflects changes made in the 1990 Amendments based 

on experience gained in the first two decades of the CAA’s implementation. 

The statute and legislative history do not expressly address the question, 
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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, 

the EPA would set emission standards for each of the affected 

EGUs in the federal-plan state, provide mechanisms for their 

 

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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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 

does not, and needs not, propose an implementation approach of 

directly intervening to re-dispatch certain units, construct new 
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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 CAA 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 EGs. See section V.A of the 

final EGs. Here we supplement that discussion with respect to 

the agency’s own authority under CAA section 111(d)(2) to use 

trading as a method of implementation of a “standard of 

performance” in the federal plan.

The 1990 CAA Amendments added broad authorizations for the 

use of market techniques in several sections of the statute, 

including in Title I. States were provided express authority to 

use such approaches in their NAAQS implementation plans under 

CAA section 110(a)(2)(A): “Each [state] plan shall—include 

enforceable emission limitations and other control measures, 
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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 

of market techniques throughout the CAA, 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).
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Case law throughout the history of the CAA has generally 

confirmed the legal viability of emissions trading as an 

implementation measure so long as the trading ultimately 

achieves the emission reduction goals of the statute. See, e.g.,

Sierra Club v. EPA, No. 12-3169 (6th Cir. Filed March 18, 2015), 

Slip Op. at 11-14 (upholding EPA approval of redesignation of 

area to attainment on basis that reductions in emissions from 

cap-and-trade programs (NOx SIP Call, CAIR, and CSAPR) are 

permanent and enforceable). Chevron, U.S.A., Inc. v. Natural 

Res. Def. Council, Inc., 467 U.S. 837 (1984) (“Chevron”), the 

seminal case establishing the Supreme Court’s standard of review 

of agency interpretations of the statutes they administer, 

upheld one of the EPA’s early emissions trading programs, the 

Netting Rules of 1980 (45 FR 52676; Aug. 7, 1980), which the EPA 

in its discretion chose to allow states to apply in both 

attainment and nonattainment areas (46 FR 50766; Oct. 14, 1981). 

The Netting Rules allowed existing major sources to modify 

without triggering certain requirements of PSD or nonattainment 

NSR, so long as any increase in emissions associated with the 

modification is compensated for by a corresponding decrease in 

emissions elsewhere within the same facility, such that there is 

no significant net increase in emissions from the facility as a 

whole. In upholding this approach in Chevron, the Supreme Court 

gave deference to the EPA’s definition of the term “source,” 
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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).45

With the increasing recognition of the utility of trading, 

crediting, and averaging to meet emission reduction goals

efficiently, the EPA set forth a comprehensive policy on trading 

in 1986. Emissions Trading Policy Statement; General Principles 

for Creation, Banking and Use of Emission Reduction Credits, 51 

FR 43814 (Dec. 4, 1986) (hereinafter “ERC Policy”). In the ERC 

Policy, the EPA stated that it “endorses emissions trading and 

encourages its sound use by states and industry to help meet the 

goals of the CAAt more quickly and inexpensively.” At the same 

 

45 The EPA is not aware of any case since at least the Chevron decision in 

which a trading program under the CAA was invalidated simply by virtue of 

being a trading program. The CAIR trading program was set aside by the D.C. 

Circuit because the court held it did not accomplish the objective of the 

Good Neighbor provision of the CAA, not because it used a trading approach 

per se. North Carolina v. U.S. EPA, 531 F.3d 896, 921 (D.C. Cir. 2008). More 

recently the Supreme Court upheld key portions of the CSAPR trading program 

that replaced CAIR in EPA v. EME Homer City, 134 S. Ct. 1584 (2014).
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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 doublecounting), determining the appropriate baseline from which to 

measure emissions, and demonstration of actual air quality 

benefits.

The use of an emissions trading system for CO2 reductions 

for affected EGUs under CAA section 111(d) is also analogous to 

the trading system for chlorofluorocarbons (CFCs) under the pre1990 CAA provision for control of stratospheric ozone depleting 

substances. This program was reviewed by the Office of Legal 

Counsel (OLC) within the Department of Justice in 1989. See

Memorandum for Alan Raul, General Counsel, Office of Management 

and Budget, from the Office of the Assistant Attorney General 

(April 14, 1989) (hereinafter “OLC Memo”).46 The OLC was asked by 

OMB to opine whether a general grant of regulatory authority to 

the EPA to “control” CFCs was sufficient to authorize an 

emissions fee or a cap-and-trade system, including auction, of 

tradable allowances. The statute authorized the EPA to issue 

regulations “for the control of any substance, practice, 

 

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

rulemaking.
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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 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 
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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 SIPs and 

FIPs for NAAQS. See 42 U.S.C. 7410(a)(2)(A), 7602(y). In the 

wake of the 1990 Amendments, the EPA issued an “Implementation 

Strategy for the Clean Air Act Amendments of 1990.”47 This 

Strategy included as one of nine overarching implementation 

principles, “Market-based: Use of market-based approaches and 

other innovative strategies to creatively solve environmental 

problems.” Further, it announced that the EPA would make “full 

use of innovative market-based approaches,” and that the agency 

will supplement traditional approaches with broader use of 

market incentives and other innovative approaches “whenever 

possible.” Id. At 3, 9.

Since the 1990 Amendments, the EPA has established three of 

its most robust trading programs – the Federal NOx Budget Trading 

Program (65 FR 2674; Jan. 18, 2000), the CAIR (71 FR 25328; 

April 28, 2006), and the CSAPR (76 FR 48208; Aug. 8, 2011), 

 

47 U.S. EPA, Office of Air and Radiation, Implementation Strategy for the 

Clean Air Act Amendments of 1990 (Update, 1992) (July 1992), 400-K-92-004.
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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.48

As noted in the rulemaking notice for the final 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 EGs in 1995. 60 

FR 65387, 65402 (Dec. 19, 1995) (codified at 40 CFR 60.33b(d)(1) 

and (2)). The EPA also developed a cap-and-trade system for 

mercury under CAA section 111(d) in the Clean Air Mercury Rule 

(CAMR). 70 FR 28606 (May 18, 2005). The EPA proposed a federal 

plan for trading that was identical in all relevant respects to 

the CAMR rule. 71 FR 77100 (Dec. 22, 2006). However, CAMR was 

vacated by the D.C. Circuit on grounds unrelated to the 

establishment of a trading system for implementation before the 

CAMR federal plan could be finalized. New Jersey v. EPA, 517 

F.3d 574 (D.C. Cir. 2008).49

 

48 The EPA notes that complications that arise with respect to assigning a 

“significant contribution” among upwind states for NAAQS pollutant levels in 

downwind states, and designing a trading regime that accomplishes Good 

Neighbor objectives, are not present with respect to CO2, which is a global 

pollutant; emission reductions anywhere contribute to the environmental 

objective of addressing climate change.

49 The CAMR program was vacated because the EPA had not made requisite 

findings under CAA section 112(c)(9) in delisting EGUs with respect to 

emissions of a hazardous air pollutants (HAP). No such procedural concern is 

present here with respect to CO2, which is not a HAP under CAA section 112.
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The agency believes these legal and administrative 

precedents for federal trading programs under the CAA going back 

decades amply support its decision to propose two forms of 

emission trading as the method of implementation of the Clean 

Power Plan EGs in the federal plan. Notably, emissions trading 

is particularly appropriate with respect to a global pollutant 

such as CO2that is well-mixed in the atmosphere and does not have 

direct, acute health impacts due to inhalation at ambient 

levels.50

Finally, the Supreme Court has affirmed the breadth of the 

agency’s discretion under CAA section 111(d) to select the 

method by which it would control CO2emissions 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 GHG-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 

 

50 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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achievable, our Nation’s energy needs and the possibility of 

economic disruption must weigh in the balance. The CAA entrusts 

such complex balancing to the EPA in the first instance, in 

combination with state regulators.”). 

This proposal is guided by the relevant cases and the 

experiences of the agency in implementing the CAA trading 

programs discussed above. The EPA invites comment on this 

discussion and the agency’s interpretation that CAA section 

111(d)(2) authorizes the two approaches to a federal plan

proposed here.

IV. Rate-based Implementation Approach

A. Overview

The EPA’s federal plan requirements for CO2 from affected 

EGUs implement the EGs as previously discussed. In this federal 

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

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 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 

Clean Power Plan EGs, which included sub-categorized CO2 emission 

performance rates for affected EGUs to meet during the plan 
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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 Clean 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 VIII.K of the 

final EGs. Under a rate-based federal plan, the EPA would act as 

the state described in section VIII.C.1.a of the final EGs with 

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 the proposed rate-based federal plan 

and model trading rule and how each would be designed and 

operated, consistent with the EGs. 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 whether to limit the scope of the federal plan in 

this manner, and if not, what other sources of low- or zero-
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emitting electricity in federal plan states should also be 

eligible to generate ERCs for compliance purposes. For both the 

proposed federal plan and model rule, the EPA requests comment 

on which EM&V plan, 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 eligible to generate ERCs can be found in the Clean Power 

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

reopening its determination of the BSER.)

B. Rate Goals

In the Clean Power Plan the EPA identified a rate-based

“emission standards” approach as an approvable method for state 

plans to implement the final EGs. In this approach the 

requirements for compliance rest solely on affected EGUs in the 

form of federally enforceable emission standards expressed as a 

rate of emissions of CO2 per unit of energy output. In the 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 NGCC units) and fossil fuel fired SGUs (i.e.,

utility boilers and IGCC units)51. The CO2 emission performance 

 

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

be called “steam generating units.”
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rates set in the Clean Power Plan are reflected below in Table 6

of this preamble. The EPA is proposing to apply these rates in 

the rate-based federal plan as the emission standards for NGCC

units, and SGUs, respectively. For a thorough discussion of 

affected EGU category-specific CO2 emission performance rates and 

rationale, see section VI of the final EGs. These calculated 

standards and the premises that these standards are based on are 

not within the scope of comment in this rulemaking as they were 

finalized in the Clean 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 3-year period (2022 through 2024), followed by a 3-

year period (2025 through 2027), followed by a 2-year period 

(2028 and 2029), for the Interim Period; and, commencing in 

2030, successive 2-year compliance periods for the Final Period. 

In the Clean 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 Clean Power Plan as the 

emission rate standard for the respective EGUs that would become 

subject to this proposed federal plan if finalized. The EPA is 

not opening for comment the determinations made in the Clean 

Power Plan of each subcategorized CO2 emission performance rates. 
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The emission rate standards for respective EGU types are 

provided for convenience in Table 6 of this preamble.

The EPA is proposing to use a glide path during the Interim 

Period for EGUs to provide a smooth transition to the final 

compliance periods after 2030. This approach is 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 provides an incentive structure, as 

compared to other rate-based approaches, that facilitates 

implementation of measures identified as part of the BSER. Using 

subcategorized rates allows for: (1) consistently applied 

emission rates for power plants of different types ; and (2) 

free trading of fungible ERCs among all affected EGUs subject to 

the federal plan and within the federal trading program. The EPA 

solicits comments on whether the subcategorized rate approach is 

the preferred rate-based approach for the federal plan and model 
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trading rule.52 If a subcategorized approach for a rate-based 

model rule and federal plan is not preferred by commenters, the 

EPA requests comment on the perceived benefits of an alternative 

rate or set of rates (e.g., applying a uniform rate, i.e., the 

state goal, to all affected units within the state as the EGUs’ 

emission standard).

C. Crediting Mechanism

Under a rate-based emission standard approach in the 

federal plan, we are proposing that EGUs subject to the emission 

performance requirements for GHGs will either need to emit at or 

below their emission rate standard, or they will need to acquire 

ERCs to achieve compliance. An ERC is a tradable compliance unit 

representing one MWh of electric generation (or reduced 

electricity use) with zero associated CO2 emissions. These ERCs 

may then be used to adjust the measured and reported CO2 emission 

rate of an affected EGU when demonstrating compliance with a 

rate-based emission standard. For each ERC, one MWh is added to 

the denominator of the reported CO2 emission rate, resulting in a 

lower adjusted CO2 emission rate.

Under this proposed federal plan, ERCs will be issued by 

the EPA to three categories of entities: (1) Affected EGUs that 

perform at a rate below the applicable emission rate standard;

 

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

open for comment.
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(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.8 of this preamble. We are also discussing 

in this preamble, taking comment on for the federal plan, and 

proposing for the model trading rule a potential fourth 

category: other low- and zero-emitting non-BSER measures that 

are described in section IV.C.3 of this preamble. The concept of 

using an ERC as a crediting mechanism to meet compliance 

obligations is consistent with the CPP EGs and is being adopted 

in this federal plan.53

Because the goal of this rulemaking is the actual reduction 

of CO2 emissions, it is fundamental that ERCs represent the MWh 

of energy generation or savings they purport to represent. To 

this end, only valid ERCs that actually meet the standards 

articulated in this rule may be used to satisfy any aspect of 

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 

 

53 The use of ERCs and definition as a compliance mechanism to meet the BSER 

emission performance rates is established in section VIII.K of the final EGs. 
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ERC issuance and tracking systems, such as the review of 

eligibility applications and M&V reports, and EPA issuance of 

ERCs, ERCs may be issued that do not, in fact, represent 

eligible zero-emission MWh as required in the EGs. A variety of 

situations may result in such improper ERC issuance, ranging 

from simple paperwork errors to outright fraud. The EPA requests 

comment on ways that the EPA could safeguard the validity of an 

ERC.

1. ERCs Generated and Owed Against a Standard

The number of ERCs generated or needed for surrender by an 

affected fossil fuel-fired EGU is based on the CO2 emission rate 

of the EGU in comparison to an emission rate standard. The 

calculation of ERCs generated by an EGU or needed for compliance 

is the CO2 stack emission rate of the EGU subtracted from the 

standard the EGU is subject to, and this value is subsequently 

divided by the standard the EGU is subject to. This value is a 

normalized quantity of how much better or worse the EGU is 

performing compared to its standard. The normalized value is 

weighted by multiplying the MWh electricity output from the EGU 

at that emission rate. This can be generically expressed as:

ERCs = (EGU standard − EGU operating rate)

EGU standard ∗ EGU generation

If the value calculated is positive, this indicates the 

number of ERCs that are being generated; conversely, a negative 
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value indicates how many ERCs will need to be acquired to meet 

the unit’s emission rate for that compliance period. ERCs will 

be issued on an annual basis to ERC providers (i.e., entities 

generating ERCs via the ERC approval and issuance process 

detailed below). Surrender of ERCs for compliance by affected 

EGUs will not occur until the end of the compliance period as 

further described in section IV.D.10 of this preamble.

As an example, assume a steam EGU operating in the second 

interim compliance period is subject to a rate standard of 1,500 

lbs CO2/MWh. Assume it operates at 2,000 lbs CO2/MWh, and also 

assume it generates 1 million MWh over a compliance period. Its 

total emission rate would be 2 billion lbs CO2 / 1 million MWh. 

In order to achieve the emission standard, it would need to 

purchase 333,334 ERCs (rounded to the nearest higher integer). 

In essence, this quantity of ERCs represents the quantity of MWh 

that need to be added to the steam EGU’s denominator (i.e.,

generation, here, 1 million MWh), such that 2 billion pounds of 

CO2 (total emissions), divided by total generation (i.e., in this 

case, 1,333,334 MWh) equals the emission rate for compliance 

(1,500 lbs/MWh). 

The discussion in this subsection builds on and applies the 

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

the final EGs (section VIII of the final EGs). We invite comment 

on use of the approach just described as a method of 
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implementation of a federal plan and a model trading rule, and 

we take comment on any alternatives to this approach that still 

fall within the established criteria described in the CPP EGs. 

Comments that solely relate to determinations finalized in the 

EGs will be considered outside the scope of this proposed rule.

2. Incremental NGCC ERCs

Building Block 2 (BB2) of the BSER determination in the CPP 

EGs describes shifting generation from SGUs to NGCC units 

because NGCC units generate electricity at a less carbon 

intensive rate. BB2 describes NGCC units generating at 75 

percent of the unit’s annual operating capacity. This level of 

generation, 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.54 The EPA is proposing to reflect

the emission reductions of BB2 by crediting all NGCC generation 

on a pro-rata basis that reflects expected incremental NGCC 

generation to 75 percent capacity. This means that for every 

hour that an NGCC generates electricity, it will also generate a 

partial credit associated with the generation shift from fossil 

steam to NGCC units. The NGCC will generate a partial credit

 

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

displacing fossil fuel-fired steam EGU generation.
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because the emission reductions associated with BB2 have been 

distributed on an hourly basis. A discussion on the concepts 

behind the distribution of emission reductions of incremental 

NGCC generation on an hourly basis can be found at the end of 

this subsection. 

All affected NGCC generation will be credited, with ERCs,

by a factor that represents the described emission reductions 

from incremental generation; ERCs credited in this way will be 

designated as Gas Shift ERCs (GS-ERCs) for clarity55. The 

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

emission reductions described in BB2 when 75 percent capacity is 

achieved. This incentive is not a requirement, however. If NGCC 

units do not collectively increase to 75 percent capacity or 

above, the lost opportunity for ERC generation simply will need 

to be achieved through other means (e.g., emissions performance 

improvements at affected EGUs or additional RE generation). The 

amount of GS-ERCs the EPA proposes to be generated for every MWh 

of NGCC operation is set at a factor relating the amount of 

electricity generation that NGCC units collectively would

generate at the level described in BB2 (i.e., reaching 75 

percent capacity) and the associated emission reductions. This 

 

55 A GS-ERC is treated and represents the same value as an ERC, but has a 

compliance restriction that it can only be used by steam generating units and 

not by stationary combustion turbines for compliance obligations.
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means that fractional GS-ERCs are generated for every NGCC MWh 

and when the interconnect region collectively reaches the level 

that would be generated if all NGGCs in the region operated at a 

75 percent capacity factor there will be an amount of GS-ERCs 

that correlates to the emission reductions anticipated under BB2 

of the BSER. NGCC units are expected to be incentivized to reach 

this level of generation in part due to market demand for GSERCs. Thus, GS-ERCs have the potential to play an important role 

in the sector meeting compliance obligations. 

The number of GS-ERCs that an NGCC generates is a 

combination of three factors. The first is the GS-ERC Emission 

Factor. This emission factor represents how much better an 

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 reference 

here is as described above in section IV.B of this preamble and 

established in the BSER determination from the EGs of the least 

stringent region56 (i.e., the region with the highest calculated 

emission rate standard for SGUs). The GS-ERC Emission Factor is 

expressed by taking the complement of the ratio of the NGCC 

 

56 The regions that are used in the CPP EGs and for this proposal are the 

Eastern Interconnect, Western Interconnect, and Electric Reliability Council 

of Texas (ERCOT). 
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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 MWh that is 75 percent NGCC 

generation capacity, giving a factor. This factor can be 

summarized by the following expression:

Incremental Generation Factor = 1 − Regional 2012 NGCC Baseline

75 % NGCC Regional Capacity

The Incremental Generation Factor is a factor that the EPA will 

calculate and will be calculated for every compliance period

based on the least stingent region’s Incremental Generation 

Factor based on increased utilization of RE and its replacement 

of fossil fuel fired generation (based on Building Block 3 of 

the CPP EGs).57 For the calculation of this factor the EPA is 

 

57 Note that per the discussion in section VI of the final EGs, if the EPA had 

measured incremental NGCC generation for reassignment to fossil steam rate as 

the difference from the post building block three levels and full 

utilization, the post building block three levels would be used in the 
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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

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 

 

numerator here, resulting in a higher “incremental generation factor” and 

more ERCs for the same amount of NGCC generation.
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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 

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 
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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 

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 GS-
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ERC 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 

year’s Average GS-ERC Emission Factor to account for the 

individual NGCC’s emission rate instead of the average NGCC 

emission rate.

The calculation of GS-ERCs for an NGCC is independent of 

the calculation of ERCs generated or owed against the NGCC 

standard. It is possible that an NGCC will owe ERCs against its

assigned emission standard for every MWh generated, but still be 

generating GS-ERCs. GS-ERCs may only be used to meet steam 

generation units’ compliance obligations.

As an example, an NGCC is connected to the grid and 

generates 1 million MWh of electric output for the first year of 

the final performance period. During this year it emits 850 
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million lbs of CO2 giving it an emission rate of 850 lbs CO2/MWh. 

The NGCC is subject to a Final Period emission rate limit of 771

lbs CO2/MWh. Since the NGCC is always subject to its NGCC 

emission rate standard of 771 lbs/MWh and it is operating at a 

rate above that standard it will owe non GS-ERCs for its own 

compliance. The ERCs owed are calculated by solving for the 

number of ERC MWh the NGCC will need to adjust its rate down to 

its emission rate limit. This is shown in the following 

equation:

850,000,000 lbs 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 102,464 ERCs to adjust 

its emission rate to its emission rate standard.

Additionally, the GS-ERC Emission Factor for this NGCC is 

calculated by using 771 lbs CO2/MWh for the NGCC emission rate 

and 1,404 lbs CO2/MWh for the SGU emission standard in the 

equation described above. 

GS-ERC Emission Factor = 1 − 771 lbs/MWh

1,404 lbs/MWh

This calculation results in a GS-ERC Emission Factor of 

0.45. This is only an example. Because the Incremental 

Generation Factor is calculated by the EPA, it can be found in 

the GS-ERC TSD and is proposed to be 0.26. By using the GS-ERC 

Emission Factor and Incremental Generation Factor calculated 
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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 = GS-ERC

The calculation results in 117 thousand GS-ERCs being 

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

to meet its compliance obligations, this NGCC will both generate 

ERCs (117,000 GS-ERCs) and owe ERCs (102,464 non-GS-ERCs against 

NGCC standard). This NGCC may sell (or otherwise transfer) or 

bank its GS-ERCs. If a GS-ERC is sold, those proceeds may, in 

turn, be used to acquire non-GS-ERCs to satisfy the NGCC’s 

compliance obligations.

A GS-ERC may not be used to meet an NGCC’s compliance 

obligation because they are generated to reflect incremental 

NGCC generation replacing a 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 the proposed approach and 

requests comment and suggestions on other approaches for 

existing NGCC units to generate GS-ERCs at all times. The EPA is 

considering this methodology that GS-ERCs are generated for all 

NGCC generation because it ensures that all existing NGCC units

are encouraged to run at a greater capacity. The EPA is 
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requesting comment on alternative methods to account for NGCC 

units generating GS-ERCs. Specifically, the EPA solicits comment 

on NGCC units generating GS-ERCs once a threshold of electric 

generation for the year is exceeded. This threshold is based on 

2012 as a baseline and any NGCC generation beyond this threshold 

would be considered incremental generation. There are two 

different options to evaluate against a baseline. The first is 

on a unit level, if 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 GS-ERCs. The other 

threshold option is to use a percentage threshold. Evaluated on 

a regional level, the 2012 baseline capacity percentage for NGCC 

units in the least stringent region is applied to all units. 

Each unit is considered to be incrementally generating after it 

exceeds the capacity percent and will be credited with GS-ERCs 

accordingly. The GS-ERCs in these instances are calculated by 

the following equation: 

GS-ERC = (Steam standard − NGCC emission rate)

Steam standard ∗ Incremental NGCC generation

This equation quantifies the reductions of the generation 

shift from fossil steam to NGCC units by the NGCC operating rate 

being evaluated against the fossil steam standard. For all 

incremental NGCC generation the NGCC operating rate is compared 

against two different standards: (1) The NGCC standard against 
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which ERC generation is evaluated; and (2) the steam standard 

against which GS-ERC generation is evaluated. An evaluation 

against each standard is independent of one another and GS-ERCs, 

in this situation, are only available for fossil steam 

compliance purposes.

While having a baseline threshold for EGU generation to 

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

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

generated by replacing NGCC generation from one unit with NGCC 

generation from another. In this situation there is not 

necessarily any additional NGCC generation as a subcategory, but 

a shift in which NGCC units are generating electricity and to 

what degree. This allows for a situation in which GS-ERCs can be 

generated without achieving the anticipated reductions in CO2

emissions.

The EPA also requests comment on whether a distinct type of 

ERC that comes with the proposed restrictions (i.e., GS-ERCs) is 

necessary to maintain the integrity of the rate-based trading

proposal. Comments regarding this section that solely relate to 

determinations finalized in the EGs will be considered outside 

the scope of this proposed rule.

3. Eligible Emission Reduction Measures for ERC Generation

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

specify emission reductions measures used to adjust an emission 
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rate that are eligible for ERC issuance under the federal plan. 

Specifically, the EPA is proposing that RE generation that meets 

the requirements for eligible resources in the EGs (as specified 

in section VIII.K of the final EGs), meets all other 

requirements related to ERC issuance in the EGs and this 

proposal, and falls into one of the following specific 

categories of RE resources (as specified in section V.E of the 

final EGs) are eligible to be issued ERCs: wind, solar, 

geothermal power, and hydropower.58 Further, the EPA is proposing 

for the federal plan that new nuclear units and capacity uprates 

at existing nuclear units that meet the requirements for 

eligible resources in the 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 

ability to provide data from a revenue quality meter, a 

requirement that is further discussed in section IV.D.8 of this 

preamble.

 

58 This treatment for RE as an eligible measure type is also proposed for the 

set-aside for RE that is part of the proposed mass-based implementation 

approach co-proposed in section V of this preamble as the federal plan, and 

all proposed aspects of the eligible measure types described in this section 

and the requests for comment included below also apply in the mass-based 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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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 RE 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 EGs for details on the treatment of these measures 

in BSER (see 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 

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, because they can use their existing metering 

infrastructure to quantify generation and submit it for ERC 

issuance. A concern unique to federal plan implementation is the 

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 
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IV.D.8 of this preamble below (see also section VIII.K.3 of the 

final EGs).

The agency requests comment on the inclusion of other 

emission reduction measures as eligible for ERC issuance under 

the rate-based federal plan. This may include other RE 

technologies not included above, such as distributed RE 

generation and various types of biomass. In this proposal, the 

EPA is also offering for comment treatment options for biomass 

fuels, if it is included as an eligible measure under the 

federal plan (see below). 

The EPA requests comment on the inclusion of various types 

of demand-side EE as eligible measures for ERC issuance under 

the federal plan, such as state and utility EE programs, 

project-based demand-side EE, state building codes, state 

appliance standards, and conservation voltage reduction. The 

agency also requests comment on the inclusion of CHP as an 

eligible measure under the federal plan. Later in this section, 

the agency has provided detailed requirements for the issuance 

of ERCs for CHP, and we request comment on these requirements 

for inclusion in the federal plan. 

The EPA requests comment on the inclusion as eligible for 

ERC issuance under the federal plan of any other emission 

reduction measures beyond those mentioned here, as long as they 

meet the eligibility requirements outlined in the final EGs for 
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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 section IV.D.8

of this preamble, and within the requirements outlined in the 

final guidelines (see section VIII.K.3 of the final EGs). It 

should also be noted that any eligible measure will be subject 

to the eligibility requirements outlined in this proposal and 

the final EGs, such as the requirement that the measure be 

incremental to 2012.

The EPA acknowledges that as new technologies mature, there 

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 

demonstrate the appropriateness of new measure types and the EPA 

could evaluate and approve the demonstration so that a new 

measure type could 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 
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requirements for eligible resources in the final EGs (as 

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

requirements related to ERC issuance under the model rule that 

are specified in the EGs and this proposal. In particular, these 

measures should be able to meet the requirements for EM&V as 

finalized in the final EGs section VIII.K and those proposed for 

the model rule in section IV.D.8 of this proposal. In this 

section, the EPA is also providing detailed requirements for CHP 

and waste heat power (WHP), these requirements are proposed 

under the model rule, and we request comment on their inclusion 

in the federal plan. We are requesting comment on the inclusion 

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

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

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 EGs, the EPA recognizes that the 

use of some biomass-derived fuels can play an important role in 

controlling increases of CO2 levels in the atmosphere (see 

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 
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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 waste-derived feedstocks 

via mandatory and voluntary programs supporting such efforts.59

Some states have also acknowledged the 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 RE incentives and standards, 

and GHG accounting procedures.60

In addition to acknowledging such state programs, the EPA 

has undertaken a technical assessment of biogenic CO2 emissions 

from stationary sources associated with the production, 

 

59 Types of waste-derived biogenic feedstocks may include: landfill gas 

generated through the decomposition of Municipal Solid Waste (MSW) in a 

landfill; biogas generated from the decomposition of livestock waste, 

biogenic MSW, and/or other food waste in an anaerobic digester; biogas 

generated through the treatment of waste water, due to the anaerobic 

decomposition of biological materials; livestock waste; and the biogenic 

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

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

60 Some states, for example Oregon and California, have programs that 

recognize the multiple benefits that forests provide, including biodiversity 

and ecosystem services protection as well as climate change mitigation 

through carbon storage. Others, like California’s Forest Practice 

Regulations, support sustained production of high-quality timber while 

considering ecological, economic and social values. Several states focus on 

sustainable bioenergy, as seen with the sustainability requirements for 

eligible biomass in the Massachusetts RPS, which, among other requirements, 

limits old growth forest harvests.
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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, concluded 

that it is not scientifically valid to assume that all biogenic 

feedstocks are “carbon neutral” and that the net biogenic CO2

atmospheric contribution of different biogenic feedstocks 

generally depends on various factors related to feedstock 

characteristics, production, processing and combustion 

practices, and, in some cases, what would happen to that 

feedstock and the related biogenic emissions if not used for 

energy production.61The EPA is engaging in a second round of 

targeted peer review on the revised Framework with the SAB in 

2015.62 Information in the revised Framework and the second SAB 

peer review process, including stakeholder comments, will assist 

the EPA in assessing potential qualified biomass feedstocks in 

federal plan applications. 

 

61Specifically, the SAB found that “There are circumstances in which biomass 

is grown, harvested and combusted in a carbon neutral fashion but carbon 

neutrality is not an appropriate a priori assumption; it is a conclusion that 

should be reached only after considering a particular feedstock’s production 

and consumption cycle. There is considerable heterogeneity in feedstock 

types, sources and production methods and thus net biogenic carbon emissions 

will vary considerably. Of course, biogenic feedstocks that displace fossil 

fuels do not have to be carbon neutral to be better than fossil fuels in 

terms of their climate impact.”

http://www.epa.gov/climatechange/ghgemissions/biogenic-emissions.html.

62 http://www.epa.gov/sab. 
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If biomass is included as an eligible measure, we are 

taking comment on an option for biomass treatment under the 

rate-based federal plan, which would also apply to eligible 

generation under the mass-based plan allowance set-aside and to 

the calculation of covered emissions for affected EGUs that are 

co-firing biomass.

This option offered for comment is to specify a list of 

pre-approved qualified biomass fuels. For example, the EPA could 

recognize the CO2 and climate policy benefits of waste-derived 

feedstocks (e.g., landfill gas) and certain industrial byproduct 

feedstocks (e.g., black liquor or other forestry and 

agricultural industrial byproducts with no alternative markets). 

As another example, the EPA could also recognize biomass 

feedstocks from sustainably managed forests lands, provided that 

these feedstocks meet certain requirements such as demonstration 

that the feedstock is sourced from sustainably managed lands 

(for example, feedstocks from forest lands with sustainable 

practices like improved management to increase carbon 

sequestration benefits) and therefore helps control increases of 

CO2 in the atmosphere. The pre-approved qualified biomass

feedstocks list could be amended in the future as the science 

related to biogenic CO2 emissions assessments evolves. The EPA 

asks for comment on whether to include a provision that allows 

sources to seek approval for other types of biomass to be added 
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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 forest- and agriculturederived biomass fuels and related CO2 benefits.

The EPA also requests comment on options for how EGUs would

demonstrate that feedstocks meet the requirements to be accepted 

as a pre-approved qualified biomass feedstocks. These 

requirements could include demonstration of certification or 

verification of practices that are additional to other 

monitoring, reporting and EM&V requirements discussed in this 

proposal, such as provision of sufficient credible analysis of 

carbon benefits, third party verification and/or certification, 

or a determination of the net biogenic CO2 effects related to the 

production, processing and use of the feedstock. 

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 
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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 section VIII.K.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 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 
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incorporation of non-affected CHP units. Electric generation 

from non-affected CHP units63 may be used to adjust the CO2

emission rate of an affected EGU, as CHP units are low-emitting 

electric generating resources that can replace generation from 

affected EGUs. Electrical generation from non-affected CHP units 

that meet the eligibility criteria under section VIII.K.1.a of 

the Clean Power Plan preamble can be used to adjust the reported 

CO2 emission rate of an affected EGU.

The electrical generation from a non-affected CHP unit that 

can be used to adjust the CO2 emission rate of an affected EGU 

must be calculated in accordance with the method specified in 

this section. The CHP unit’s electrical output is prorated based 

on the CO2 emission rate of the electrical output associated with 

the CHP unit (a CHP unit’s “incremental CO2 emission rate”) 

compared to a reference CO2 emission rate.64 This “incremental CO2

emission rate” related to the electric generation from the CHP 

unit would be relative to the applicable CO2 emission rate 

standard for affected EGUs in the state and would be limited to 

 

63 The accounting treatment described in this section is for a “topping cycle” 

CHP unit. A topping cycle CHP unit refers to a configuration where fuel is 

first used to generate electricity and then heat is recovered from the 

electric generation process to provide additional useful thermal and/or 

mechanical energy. A CHP unit can also be configured as a “bottoming cycle” 

unit. In a bottoming cycle CHP unit, fuel is first used to provide thermal 

energy for an industrial process and the waste heat from that process is then 

used to generate electricity. Some waste heat power (WHP) units are also 

bottoming cycle units and the accounting treatment for bottoming cycle CHP 

units is provided with the WHP description below.

64 The applicable CO2 emission rate standard is in Table 6. of this preamble.
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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:

CHP electrical CO2 emission rate = [CHP fuel input65 * fuel 

emission factor66 – (UTO/boiler efficiency) * fuel emission 

factor]/CHP electrical MWh

Where UTO is the useful thermal output from a 

counterfactual industrial boiler that would have existed to meet 

thermal load in the absence of the CHP unit.

This accounting approach takes into account the fact that a 

non-affected CHP unit is a fossil fuel-fired emission source, as 

well as the fact that the incremental CO2 emissions related to 

electrical generation from a non-affected CHP unit are typically 

very low. To generate ERCs for CHP, the CHP Electrical CO2

Emission Rate that is calculated (from above) is applied against 

the applicable affected EGU standards in the same fashion as 

 

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

fuel input.

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

G. 
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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 

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 
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process and the waste heat from that process is then used to 

generate electricity.67 There are also WHP facilities where the 

waste heat from the initial combustion process is used to 

generate additional power. Under both configurations, unless the 

WHP unit supplements waste heat with fossil fuel use, there is 

no additional fossil fuel used to generate this additional 

power. As a result, there are no incremental CO2 emissions 

associated with that additional power generation. As a result, 

the incremental electric generation output from the WHP 

facilities could be considered 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.68 The MWh of electrical output from a WHP unit that 

can be recognized may not exceed the MWh of industrial or other 

thermal load that is being met by the WHP unit, prior to the 

generation of electricity.69In addition, where fossil fuel is 

used to supplement waste heat in a WHP application, the EPA 

requests comment on what provisions to include in the final 

 

67 In such a configuration, the waste heat stream could also be generated from 

a mechanical process, such as at natural gas pipeline compressors.

68 This only applies where no additional fossil fuel is used to supplement the 

use of waste heat in a WHP facility. Where fossil fuel is used to supplement 

waste heat in a WHP application, MWh of electrical generation that can be 

used to adjust the CO2 emission rate of an affected EGU must be prorated based 

on the proportion of fossil fuel heat input to total heat input that is used 

by the WHP unit to generate electricity.

69 This limitation prevents oversizing the thermal output of a WHP unit to 

exceed the useful industrial or other thermal load it is meeting, prior to 

generation of electricity.
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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

The EPA proposes that the rate-based federal trading 

program use the agency’s already-existing allowance tracking and 

compliance system (ATCS). Under the proposed rate-based trading 

program, the federal trading program would be maintained in the 

EPA’s existing data system. The ATCS would be used to track the 

trading of ERCs held by affected EGUs, as well as ERCs held by 

other entities. Specifically, the ATCS would track the 

generation of ERCs, holdings of ERCs in compliance accounts 

(i.e., accounts for affected EGUs) and general accounts (i.e.,

accounts for other entities and for affected EGUs, including 

affected EGUs that are under a ready-for-interstate-trading

state plan), deduction of ERCs for compliance purposes, and 

transfers of ERCs between accounts. The primary role of the ATCS

is to provide an efficient, automated means for covered sources 

to comply, and for the EPA to determine whether covered sources 

are complying, with the emissions rate standards. The ATCS would 

also provide data to the ERCs market and the public, including a 
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record of ownership of ERCs, dates of ERC issuance, ERC 

transfers, buyer and seller information, serial numbers of ERCs 

transferred, emissions, and compliance information. This 

information would be publicly available on the EPA’s Web site 

and in annual progress reports. The ATCS and the EPA provide all 

required elements of a qualified ERC tracking system as 

described in section VIII of the final EGs.

In the subsections that follow, the mechanisms by which a

rate-based trading program would be implemented and administered 

are detailed. The EPA requests comment on each component of the 

trading system that is proposed in this preamble and the 

associated model rule, the trading program as a whole, and 

specifically requests comment on means to expedite the process 

of issuing ERCs, any minimum and maximum periods for which ERCs 

should be issued (e.g., monthly, quarterly, annually), and any

means to 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 
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This section establishes the procedures for certifying and 

authorizing the designated representative, and alternate 

designated representative, of the owners and operators of the 

affected EGU and for changing the designated representative and 

alternate designated representative. These sections also 

describe the designated representative’s and alternate 

designated representative’s responsibilities and the process 

through which he or she could delegate to an agent the authority 

to make electronic submissions to the Administrator. These 

provisions would be patterned after the provisions concerning 

designated representatives and alternates in prior EPAadministered trading programs. 

The designated representative would be the individual 

authorized to represent the owners and operators of each 

affected EGU in matters pertaining to the rate-based trading 

program. One alternate designated representative could be 

selected to act on behalf of, and legally bind, the designated 

representative and, thus, the owners and operators. Because the 

actions of the designated representative and alternate would 

legally bind the owners and operators, the designated 

representative and alternate would have to submit a certificate 

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.
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The designated representative and alternate would be 

authorized upon receipt by the Administrator of the certificate 

of representation. This document, in a format prescribed by the 

Administrator, would include: specified identifying information 

for the covered source and covered EGUs 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.
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In addition to the flexibility provided by allowing an 

alternate to act for the designated representative (e.g., in 

circumstances where the designated representative might be 

unavailable), additional flexibility would be provided by 

allowing the designated representative and alternate to delegate 

authority to make electronic submissions on his or her behalf.

The designated representative and alternate could designate 

agents to submit electronically certain specified documents. The 

previously-described requirements for designated representatives 

and alternates would provide regulated entities with flexibility 

in assigning responsibilities under the rate-based trading 

program, while ensuring accountability by owners and operators 

and simplifying the administration of the proposed rate-based 

trading program. 

2. ERC Tracking and Compliance System 

The rate-based trading program rules establish the 

procedures and requirements for using and operating the 

Allowance Tracking and Compliance System (which is the 

electronic data system through which the Administrator would 

handle ERC issuance, holding, transfer, and deduction), and for 

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 
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type (i.e., if it is a GS-ERC or not). ERC price information 

would not be included in the ATCS. The EPA’s experience is that 

private parties (e.g., brokers) are in a better position to 

obtain and disseminate timely, accurate price information than 

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 
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EGUs,70 and an accompanying tracking system infrastructure 

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

serial number) and the tracking system will provide traceability 

of issued ERCs back to the program or project for which they 

were issued. 

The EPA received a number of comments from states and 

stakeholders 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, which would be established by the 

Administrator for each affected EGU upon receipt of the 

certificate of representation for the source; and general 

 

70 “Compliance true-up” refers to ERC submission by an owner or operator of an 

affected EGU to adjust a reported CO2 emission rate, and determination of 

whether the adjusted rate is equal to or lower than the applicable rate-based 

emission limit.
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accounts, which could be established by any entity upon receipt 

by the Administrator of an application for a general account. A 

compliance account would be the account in which any ERCs used 

by the affected EGU for compliance with the emissions 

limitations would have to be held until retired for compliance.

General accounts could be used by any person or group for 

holding or trading ERCs. However, ERCs could not be used for 

compliance with emissions limitations so long as the ERCs were 

held in, and not properly and timely transferred out of, a 

general account. To open a general account, a person or group 

would be 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, 
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for changing the application to take account of changes in the 

persons having an ownership interest with respect to ERCs, and 

for delegating authority to make electronic submissions would be 

analogous to those applicable to comparable matters for 

designated representatives and alternates. The EPA requests 

comment on these compliance mechanisms. 

5. Compliance Demonstration

The EPA proposes that affected EGUs subject to this federal 

plan are required to meet compliance obligations by November 1 

of the year following the end of the compliance period. For an 

affected EGU to meet its compliance obligations its average 

stack emission rate over the compliance period must be at or 

below its applicable rate standard, or the affected EGU must use 

ERCs to adjust its average stack emission rate to be at or below 

its applicable rate standard. An EGU’s average emission rate 

over the compliance period will be calculated based on submitted 

data to ATCS. The compliance period average would be calculated 

by taking the measured CO2 mass in units of pounds (lbs) summed 

over the compliance period for an affected EGU and dividing it 

by the total net energy output over the compliance period for 

that affected EGU in units of MWh.71 This averaged emission rate 

will be compared to the emissions standards that the EGU is 

 

71 Note that these values will be the submitted values from the affected EGUs 

to the EPA that have gone through a transparent review process. 
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subject to during the corresponding compliance period. 

Accordingly, and if necessary, the appropriate number of ERCs 

will be retired from the EGU’s compliance account to adjust the 

emission rate of the EGU to be equal to the emission standard. 

The discussion of using ERCs for compliance is found in section 

IV.D.10 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.,
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quarterly, biannually, or other time frames). The EPA requests 

justification along with corresponding comments regarding ERCissuance intervals. We request comment on how reporting and 

recordkeeping requirements could be minimized, particularly for 

small entities, to the extent possible under the statute and 

existing regulations. 

a. Issuance of ERCs to Affected EGUs. Following the 

determination of the number of ERCs an affected EGU is eligible 

to receive, based on an affected EGU’s reported CO2 emission rate 

compared to a specified reference rate72, the EPA will issue 

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

The issuance will occur annually through the NODA process. ERCs 

will have a unique serial number, tracking number, and will 

distinguish ERC type (i.e., if it is BB2 or not) when issued to 

an affected EGU.

b. Issuance of ERCs for Measures Used to Adjust an Emission 

Rate. In the final EGs, the EPA has specified requirements for 

an ERC issuance process for the quantification and verification 

of measures used to adjust an emission rate that provide the 

necessary rigor and transparency while being efficient and 

streamlined. This is the intent of the federal plan as well, 

where there is a particular concern with implementing a 

 

72 As described in section IV.C.1 of this preamble.
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streamlined and efficient federal process for ERC issuance 

across federal plan states. As required in the final EGs, we are 

proposing a two-step application process to the federal plan 

tracking systems for ERCs that allows for project approval to 

take place prior to the performance period, and makes the 

issuance of ERCs as quick and efficient as possible after 

generation has been quantified and verified, while still 

assuring a rigorous approval process. For the first step in the 

ERC issuance application process, the EPA proposes that RE and 

nuclear generation providers submit to the EPA an eligibility 

application for EPA approval, or its designated agent, 

demonstrating that the project is eligible for the issuance of 

credits, including an EM&V plan that meets EPA requirements. The 

EPA takes comment on all aspects of the proposed ERC issuance 

process. The EPA is also taking comment on how an ERC issuance 

process would apply to emission reduction measures for which we 

are taking comment regarding their eligibility for ERC issuance 

under the federal plan, including types of RE not covered by the 

federal plan, demand-side EE, CHP, biomass, and any other 

measure that could be considered eligible under the final 

guidelines.

The following are proposed required components of the 

eligibility application, as specified for these measures in the 

final 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 is only being credited in the federal 

plan, and will not be submitted for ERC issuance in 

any other rate-based crediting system in any other 

state. As discussed in section IV.C. 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 would 

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 section IV.C of this 

preamble.

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

EM&V plan that meets the federal plan requirements. 

Proposed requirements specific to the federal plan are 

proposed in section IV.D.6 of this preamble. 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 plan. 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 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 

inclusion is further discussed in section III.A of 
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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 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 in 

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 the ERC issuance process. It will provide for transparent 

access to RE project and program eligibility applications and 

regulatory approvals as well as information on the activities of 

accredited third party verifiers (third party verifiers are 

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

for the public to be able to generate reports based on this 

information. 

The agency is proposing that the project eligibility 

applications will be accepted after the finalization of the 

federal plan and prior to the first compliance period, as soon 
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as the agency is able to establish an application process, and 

that applications will be accepted on an annual basis. The 

agency requests comment on whether a quarterly or biannual 

application process is more appropriate. These applications will 

be accepted through the entirety of all compliance periods. The 

EPA will review and approve the project applications. It is 

proposed that the EPA may designate an agent to coordinate the 

project application process and assist with review of 

applications.

For the second step in the credit issuance application 

process, the EPA proposes that providers submit an M&V report to 

the EPA, or its designated agent, prior to the EPA’s issuance of 

ERCs. This can only occur after the approval of a project 

application, the RE has been generated, and necessary EM&V has 

been completed.

The following are proposed required components of the ERC 

issuance application:

(1) Documentation of completed EM&V in accordance with 

the EM&V plan submitted by the RE provider, including 

quantification of the MWh of generation to be credited 

and verification of their creation.

(2) Documentation that the generation has not been 

submitted for crediting under any other federal or 

state plan, including to another rate-based credit 

tracking system. 

(3) Documentation that the MWh resulted from RE or 

incremental nuclear capacity eligible for crediting 

under the federal plan requirements and in accordance 

with final EGs. This documentation should note if the 
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MWh are from an RE project located in a state with a 

mass-based plan, and show if the generation is

approved to be eligible for ERC issuance under the 

federal plan. See section IV.C.3 of this preamble for 

specifics on the required demonstration for this type 

of RE generation. As discussed in that section, this 

option is proposed to not be available to incremental 

nuclear capacity located in a state with a mass-based 

plan.

(4) This application must include a verification 

report from an independent third-party verifier, 

submitted after the verifier’s review and approval of 

the eligibility application, as is reflected in EM&V 

requirements for the final guidelines, and specified 

as part of proposed federal plan EM&V requirements 

described below and included in detail in the proposed 

model rule.

If the application meets these requirements, pursuant to 

review by the EPA or its designated agent, ERCs will be issued 

to the provider by the EPA through the Allowance Tracking and 

Compliance System (ATCS). The specific steps of the process by 

which an eligible resource seeks ERCs, and by which an affected 

EGU may use ERCs in its compliance demonstration are laid out in 

the proposed model rule. One of the steps requires the proponent 

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 
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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 

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 
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and substantive process at the state level to enable them to 

rescind or withhold approval of specific credits. We request 

comment on the content of each of these provisions in the model 

rule, and specifically seek comment on whether the model rule 

should include different or additional details related to either 

procedure or substance for error correction and the revocation 

of the qualification status of an eligible resource or 

independent verifier.

The agency is proposing that ERC eligibility applications 

will be accepted starting before the beginning of the first 

compliance period (January 1, 2022), through an application 

process the agency will establish and administer (unless 

delegated or taken over through a partial state plan), and that 

applications will be accepted on an annual basis. These 

applications will be accepted through the entirety of all 

compliance periods. The EPA will review and approve eligibility 

applications, and may designate an agent to coordinate and 

assist with ERC eligibility applications. The EPA is proposing 

that it will issue ERCs for a given year no later than 6 months 

after the end of the relevant year. This amount of time may be 

necessary to accommodate the ERC issuance process, including 

necessary EM&V. The overall proposed schedule for trading and 

true-up has been constructed to allow for this period of time 

for EM&V after the compliance period.
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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 2021.73 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.

• 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).

 

73 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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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 

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 
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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 

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 
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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 

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 
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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.

The remainder of this section and the related language in 

the proposed model rule provide the proposed basis by which the 

EPA intends to evaluate the independence of the verifiers that 
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it uses to provide verification reports pursuant to the federal 

plan. The qualifications described here and in the model rule 

would be presumptively approveable in the context of a state 

plan.

As a starting point, an independent verifier must have the 

necessary technical qualifications to provide verification 

services for the subject in question, as well as fulfill certain 

codes of conduct in providing verification services. Only 

verifiers approved or “accredited” by the EPA may provide 

verification services related to ERC issuance for the federal 

plan, in the same way that only verifiers approved by a state 

may be eligible to perform verification services pursuant to a 

state plan.74

In addition, verifiers must have sufficient knowledge of 

the rate-based emission trading program rules, technical 

expertise, and knowledge of auditing, accounting, and 

information management practices, in order to perform 

verifcation services related to the Clean Power Plan. Accredited 

verifiers must be independent. Accredited verifiers may not 

provide verification services for any eligible resource for 

 

74 In this section, the term “verifier” is used interchangeably to refer to 

both a “verification body” (i.e., a verification company or organization) and 

a “verifier,” which is an individual that is a principal or employee of a 

verification body.
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which they have a financial, management, or other interest.75

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 

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 

 

75 Accredited verification bodies and individual verifiers may not have any 

direct or indirect organizational or personal relationships with an ERC 

provider that would impact their impartiality in assessing the validity and 

accuracy of the information in an eligibility application or M&V report. In 

addition to this general requirement, the following specific requirements 

also apply. Accredited verifiers must have no direct or indirect financial 

interest in, or other financial relationships with, an ERC provider or any 

related program or project that seeks issuance of ERCs. Accredited verifiers 

must have no relationship with the implementer of a program or project that 

seeks the issuance of ERCs, or any related ERC provider, that would represent 

a COI. Accredited verifiers must have no role in the development and 

implementation of a program or project that seeks issuance of ERCs, beyond 

the provision of verification services. Accredited verifiers must not be 

compensated, directly or indirectly, in relation to the quantified and 

verified MWh in an M&V report or on the basis of program or project approval, 

ERC issuance, or the number of ERCs issued. Accredited verifiers may not hold 

ERCs, or other financial derivatives related to ERCs, or have a financial 

relationship with other parties that hold ERCs or other related financial 

derivatives. Verification reports must include an attestation by the 

accredited verifier that it assessed potential COI related to an ERC provider 

and adequately addressed any identified COI. The EPA requests comment the 

potential for payments to be channeled through the EPA as fees. 
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accreditation. The EPA will perform periodic reviews of 

accredited verifiers, to ensure that verifiers are maintaining 

necessary technical and professional qualifications and are 

meeting program requirements for provision of verification 

services. The EPA may recognize, in part, accreditation by an 

outside organization where such outside accreditation 

demonstrates that federal plan requirements are met.76 The EPA 

requests comment on the proposed necessary requirements for an 

independent verifier to perform verification services in 

connection with the federal plan, including those requirements

specifically detailed in this section of the preamble and the 

related language in the proposed model rule, and including 

whether there are any requirements that are not included in this 

proposal that should be included in the final rule. We further 

request comment on the level of detail that we should include in 

the final model rule regarding all requirements for indepenent 

verifiers, and all aspects of verification.

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

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

Reports

 

76 An example is American National Standards Institute (ANSI) accreditation 

under ISO 14065:2013 for GHG validation and verification bodies. More 

information is available at 

https://www.ansica.org/wwwversion2/outside/GHGgeneral.asp.
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This section identifies and discusses the EM&V approaches

used to quantify and verify MWh from RE, demand-side EE, and 

other eligible measures used to generate ERCs or otherwise 

adjust an emission rate.77

Only a subset of the potentially creditable ERC resources 

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 

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 

 

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

approaches used to quantify the MWh from RE, demand-side EE, and other 

eligible measures and thereby ensure that the resulting savings and 

generation are quantifiable and verifiable. In this proposal, we are 

proposing EM&V for the eligible RE, and taking comment on EM&V for demandside EE and any other measures that could be eligible. 
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federal plan, the EPA requests comment on the inclusion of other 

RE measures, demand-side EE measures, and any other measures 

that may be eligible under the final guidelines as eligible 

measures under the federal plan. For stakeholders that are 

submitting comments on the inclusion of such additional 

measures, the EPA requests comment on how the EPA could 

implement across applicable jurisdictions a rigorous, 

straightforward, and widely demonstrated set of EM&V methods, 

procedures, and approaches that could be implemented in the time 

frame allowed by the federal plan and that also meet the 

requirements outlined in the final guidelines. To the extent

proposed for inclusion in the model trading rule, we also invite 

comment on these requirements in the context of state 

implementation as part of a state plan. Thus, commenters on this 

aspect of the proposal should consider whether and how these 

provisions could be implemented at the state level. Comments 

that suggest an approach not authorized by the EGs will likely 

be considered outside the scope of this proposed rule.

Additionally, with respect to EM&V, the EPA describes 

certain established industry best-practice methods, procedures, 

and appraoches that would be presumptively approvable if 

included in state plans. States wishing to adopt the model rule 

must submit these methods, procedures, and approaches as 

specified, or may submit alternative EM&V that is functionally 
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equivalent to the industry best-practices described as 

presumptively approvable.78

As discussed in section IV.C.3 of this preamble, quantified 

and verified MWh of RE generation and other means of generating 

ERCs may be used to adjust a CO2 emission rate when demonstrating 

compliance with the 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.79

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 

 

78 The EPA recognizes that EM&V is routinely evolving to reflect changes in 

markets, technologies and data availability, and expects to update its EM&V 

guidance over time. Therefore the agency expects that alternative 

quantification approaches will emerge that can be approved for use, provided 

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

outlined in this section. 

79 A full discussion of applicable requirements for the establishment and 

functioning of the rate-based trading system is provided above, in section 

IV.D of this preamble.
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associated “State Plans Considerations” TSD80 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 

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 

 

80 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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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, 

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 
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in which the energy generated or saved by the eligible resource 

will be quantified, monitored and verified. The manner of 

quantification, monitoring and verification must meet the 

criteria outlined below and included in the proposed model rule, 

as applicable to the specific eligible resource. We take broad 

comment on each criteria specified below and in the proposed 

model rule, for each eligible resource. Specifically, we seek 

comment on the substantive content of the criteria, and we seek 

comment on the level of detail provided and whether more or less 

detail (and what detail) should be included in the final model 

rule, and whether the criteria should differ for each eligible 

resource.

Each M&V report submitted in support of the issuance of 

ERCs to a specific eligible resource must include specific 

criteria described here and in the proposed model rule. For the 

first M&V report submitted, a key component is documentation 

that the electricity-generating resources or electricity-saving 

measures were installed or implemented consistent with the

description in the approved eligibility application. Each 

following M&V report must then identify the time period covered 

by the M&V report, describe how the methods specified in the 

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 
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M&V report. Any change in the energy generation or savings 

capability of the eligible resource during the period covered by 

the M&V report must also be included in the M&V report, along 

with the date on which the change occurred, and information 

sufficient to demonstrate whether the eligible resource 

continued to meet all eligibility requirements during the period 

covered by the M&V report. Any change should also be specified 

in the report. The EPA takes broad comment on each of these 

criteria, as described here and in the proposed model rule. 

Specifically, we seek comment on the substantive content of the 

criteria, and we seek comment on the level detail provided and 

whether more or less detail (and what detail) should be included 

in the final model rule, and whether the criteria should differ 

for each eligible resource.

Each verification report submitted by an independent 

verifier in support of the issuance of ERCs to a specific 

eligible resource must address the criteria described here and 

in the proposed rule text. Each verification report must set 

forth the findings of the verifier, based on an assessment of 

all relevant requirements, information and data, including an 

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 
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resource to be issued ERCs; that the eligible resource exists 

and has been, or will be, generating energy or saving 

electricity in the manner required; that the EM&V plan meets its 

requirements; and any other information required or that the 

verifier finds, in its professional opinion, is necessary to 

assess the accuracy of the subject of the verification report. 

Each verification report included as part of a M&V report must 

also describe the review conducted by the verifier and verify

the following: the adequacy and validity of the information and 

data submitted to quantify eligible MWh of electric generation 

or electricity savings during the period covered by the report, 

as well as all supporting information and data identified in the 

EM&V plan and M&V report; evaluate whether all generation or 

savings data is within a technically feasible range for that 

specific eligible resource (determined through a quality 

assurance and quality control check of the data); that the M&V 

report meets its requirements; and any other information 

required or that the verifier finds, in its professional 

opinion, is necessary to assess the accuracy of the subject of 

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) 
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should be included in the final model rule, and whether the 

criteria should differ for each eligible resource.

For demand-side EE, all EM&V plans that are developed for 

purposes of adjusting an emission rate under this final rule are 

intended to leverage and closely resemble the plans already in 

routine use for a wide range of publicly or rate-payer funded EE 

programs and energy service company (ESCO) projects. For RE, 

EM&V plans similarly leverage resources and approaches to MWh 

tracking for RE that are broadly applied in the state and 

regions. The existing reports and documentation from existing 

tracking systems may serve as the substantive basis for a 

monitoring and verification report for RE.

b. Renewable Energy EM&V Requirements. This section describes 

the EM&V requirements associated with quantifying electricity 

generation from eligible RE and nuclear, and for documenting 

these requirements in EM&V plans and reports. Consistent with 

prevailing views expressed in public comments, the EPA’s 

requirements presume that the 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 
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with state RPS policies. A key element of RPS compliance is that 

each RE generating unit must be uniquely identified and recorded 

in a registry to avoid the double counting of RECs.

The primary metric for all RE is electricity generation, in 

units of MWh. Measured output must be derived either from (1) A

revenue quality meter that meets the applicable ANSI C-12 

standard or equivalent, which is the typical requirement for 

settlements with RTO and other control-area operators; or (2) 

for customer-sited generators that are interconnected behind the 

customer meter, measurement at the AC output of an inverter, 

adjusted to reflect the energy delivered into either the 

transmission or distribution grid at the generator bus bar. 

Further, a RE generating facility of 10 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 
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energy accounting or settlements process, and reported by the 

control area operator to the REC registry at least monthly. The 

EPA requests comment on this proposed requirement for 

quantifying RE generation for the purpose of ERC issuance.

For RE units that do not go through a control area 

settlements process, metered data may be read and transmitted to 

the ERC registry by an independent third party, or may be selfreported. Third-party and self-reported generation data must be

reported on an annual basis. All such data must be verified for 

reasonableness by the agency, state or the REC registry. 

For reporting purposes, RE generation may be aggregated 

from multiple generators into a single MWh value for the group, 

provided the following requirements are met: each RE unit is 

uniquely identified in the federal tracking system, the 

nameplate capacity of each RE unit is less than 150 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 
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of RE generation is uniquely identified and recorded to avoid 

double counting.

An additional criterion that applies to distributed RE 

units that directly serve on-site end-use electricity loads is 

that avoided transmission and distribution (T&D) system losses 

can be considered, as is commonly practiced with demand-side EE. 

Such calculations must apply the requirements specified for 

demand-side EE as described below. 

The EPA requests comment on all metering, measurement, 

verification, and other requirements included in this 

subsection, includuing the appropriateness of their use for each 

type of 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 
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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 

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 
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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 

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, 
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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.

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 
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output.81 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 facilities82 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 

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 

 

81 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.

82 A CHP facility may consist of one or more electric generators.
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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. 

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 
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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 

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 
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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 

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 
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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.

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 
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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 

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 
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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 

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 
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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.

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 
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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). 

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 
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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 losses83 will be quantified and 

applied to EE savings determined at the customer facility 

or premises. The EPA is proposing that demand-side EE 

programs (other than T&D efficiency measures such as CVR 

and volt/VAR optimization84) 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.85

• 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. 

 

83 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).

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

final EGs.

85 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.
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• How the accuracy and reliability of quantifying MWh savings 

values will be assessed, and the rigor86 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.

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 

 

86 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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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 

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.
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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.

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 
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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.

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 
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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.

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, 
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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 

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 
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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 

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 
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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 

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 
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certification standards can help to assure quality and 

credibility of demand-side EE,RE and other carbon emission 

reduction projects. The EPA also recognizes that a skilled 

workforce performing the EM&V is important to substantiate the 

authenticity of emissions reductions.

The EPA agrees that in conjunction with other EM&V measures 

discussed in this section, and in the context of the model 

trading rules although this is not an aspect needed for 

presumptive approvability, states are encouraged to include in 

their plan a description of how states will ensure that workers 

installing demand side EE and RE projects, or other measures 

intended to reduce CO2 emissions, as well as workers who perform 

the EM&V of demand side EE and existing EGU performance will be 

certified by a third party entity that:

• Develops a training or competency based program aligned 

with a job task analysis and/or certification scheme;

• Engages with subject matter experts in the development of 

the job task analysis and/or certification schemes that 

represent appropriate qualifications, categories of the 

jobs, and levels of experience;

• Has clearly documented the process used to develop the 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 
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third party accrediting body recognized by DOE; or parties 

aligned with an apprenticeship program that is registered with 

the federal Department of Labor (DOL), Office of Apprenticeship; 

or with a state apprenticeship program approved by the DOL, or 

by another skill certification validated by a third party 

accrediting body can help to substantiate the authenticity of 

emission reductions due to demand-side EE and RE and other 

carbon emission reduction measures.

9. ERC Transfers and Trading

All affected EGUs that may be subject to this proposed 

federal plan would be required to be a part of the allowance 

tracking and compliance system (ATCS) that the EPA runs, 

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

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 

above in section IV.D.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 
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data consistent with part 75.87 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.C.3 of this preamble 

for a comprehensive discussion of non-EGU ERC generating 

sources). The data must follow the EM&V procedures delineated in 

section IV.D.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.D.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 

 

87 See section IV.D.11 of this preamble for more information.
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at midnight of the year following the conclusion of the 

compliance period.88

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 

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 

 

88 This true-up process is further described in section IV.D.8 of this 

preamble.
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compliance period. For example, if the first compliance period 

comprises the three years 2022, 2023, and 2024, then the ERC 

transfer deadline89 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 ERC

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 compliance period 

that includes the year for which the ERC was issued or be 

averaged into a later compliance period. Consequently, each 

affected EGU would need, as of the ERC transfer deadline, to 

have in its compliance account enough ERCs usable for its 

compliance obligations for the compliance period. The authorized 

account representative could identify specific ERCs to be 

applied, but, in the absence of such identification or in the 

case of a partial identification, the Administrator would deduct 

on a first-in, first-out basis. The ERCs that are used to meet 

compliance obligations are moved from the compliance account to 

the EPA’s retirement account. ERCs that are deducted for 

 

89 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 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 

(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. 

Adjusted Emission Rate = Mass of CO2 emitted (lbs)

Generation (MWh) + MWh ERCs

This equation can be rearranged to:

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 
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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 

CAA. This requirement to surrender two times the ERCs needed to 

make up the shortfall for the prior period is an ongoing 

obligation until compliance is achieved, and there is 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 
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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 

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 ARP and Cross State Air Pollution Rule (see, e.g., 40 CFR 

72.96, 73.37, 97.427, and 97.428). The EPA solicits comment on 

potential alternatives for error correction that is simpler or 

more efficient. 

12. Banking of ERCs

The EPA is proposing to allow unlimited banking or ERCs 

within and between the interim and final compliance periods. 

This means that if an affected EGU has more ERCs than are 

necessary during true-up, it may save (i.e., bank) those ERCs 

for application during a future compliance period. The EPA 

requests comment on whether there should be a quantitative limit 

or cap on the number of ERCs that can be banked. The EPA also 
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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 

acquire in a future compliance period to meet its current 

compliance obligations. The EPA requests comment on a 

methodology that would allow ERC borrowing while maintaining the 

integrity of the compliance obligations. The EPA also has 

reservations due to the fact that future ERC generation is not 

guaranteed. 

13. Emissions Monitoring and Reporting

The EPA would require that emission and generation data be 

reported to the EPA quarterly starting on April 30, 2022, and 

continuing every 3 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 
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monitor and report CO2 emissions by and output data by January 1, 

2022. Quarterly reporting would be required, with each quarterly 

report due to the Administrator 30 days after the last day in 

the quarter. The reporting would be in accordance with 40 CFR 

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 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 ARP, 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 ARP are subject to the MATS program and therefore will have 

already installed stack flow rate and/or CO2 monitors in order to 

comply with the MATS rule which are also necessary to comply 

with this rule. The CEMS used to comply and report data for MATS 

will be used for this rule to generate and report CO2 emissions 

data without having to install duplicative monitors. The same CO2 
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and stack gas flow rate monitored data used in conjunction with 

mercury 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. 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 

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 RGGI programs and will have minimal additional 

monitoring and reporting requirements.

The EPA also requests comment on requiring monitoring and 

reporting of CO2 mass and net generation for the year before the 

initial compliance period begins, i.e., to commence January 1, 

2021. Only monitoring and reporting would be required in 2021 —

compliance with an enforceable emission standard would commence 

on the compliance period schedule that is detailed in section 

III.D of this preamble.
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E. Federal Plan and State Plan Interactions

1. Interstate Trading

The EPA proposes that all affected EGUs within states that 

are covered by the federal plan, if a rate-based federal plan is 

finalized for two or more states, would be allowed to trade with 

one another since there will be an assured commonality in the 

ERC currency and criteria surrounding the trading program. In 

addition, the EPA proposes, consistent with the provision for 

“ready-for-interstate-trading” plans in the EGs that affected 

EGUs located in states with approved ready-for-interstatetrading state plans using the sub-categorized uniform rate 

standards, and a common credit currency (i.e., ERCs representing 

one zero-emitting MWh) may trade with affected EGUs operating 

under the federal trading program established in this federal 

plan. 

Rate-based EGUs subject to the federal plan and rate-based 

EGUs in ready-for-interstate-trading state plans will be able to 

trade ERCs seamlessly across jurisdictional borders because of 

the assurances of being presumptively approvable. Ready-forinterstate-trading states must submit information that lists all 

affected EGUs and the EGU type to the Administrator to be able 

to trade within the federal trading program. To be able to trade 

in the federal trading program an affected EGU that is subject 

to a ready-for-interstate-trading state plan must: (1) Certify 
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and authorize a designated representative per section IV.D.1 of 

this preamble; and (2) register a general account in the federal 

trading program, ATCS, in order to have a 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 ready-forinterstate-trading. A state’s program can be tailored to meet 

its needs while still providing a platform for a state to be 

transferring ERCs between the state’s system and the federal 

trading program. ERCs can flow between a state system and the 

federal trading program bilaterally. The EPA acknowledges that 

states may have additional criteria for generating ERCs that are 

not outlined as part of the federal plan, but because the EPA 
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will have vetted these criteria through a state plan approval 

these ERCs will be able to be traded within the federal trading 

program. 

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

The EPA proposes that a rate-based trading federal plan may

be replaced by a state plan for a future compliance period. The 

EPA is proposing that a state must transition to a state plan at 

the conclusion of a federal plan compliance period. The EPA 

requests comment on whether there are reasons that a state 

should be allowed to transition from a federal plan to a state 

plan in the middle of a compliance period and if so what 

requirements should be put in place to do so while ensuring the 

integrity of both the federal plan and the state plan and while 

enabling the affected EGUs covered by the plans to understand 

and meet their compliance requirements. If a state subject to 

the federal plan transitions to a state plan, any affected EGU 

impacted by the change remains responsible for meeting any 

outstanding obligations under the federal plan. To make the 

transition to a state plan, a state must have an approved state 

plan as laid out in sections 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 
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implementation approach for the federal plan. As with the ratebased approach, this proposed federal plan is also a proposed 

model trading rule that states can adopt. The mass-based 

approach that the agency proposes to implement is a mass-based 

trading program (i.e., an emissions budget trading program, also 

referred to as an “allowance system”). This section provides a 

brief overview of the proposed mass-based trading program. The 

next sections describe the various elements of the proposed 

trading program in further detail.

A mass-based trading program establishes an “aggregate 

emissions limit” that specifies the maximum amount of emissions 

authorized from affected EGUs included in the program, and 

creates allowances that authorize a specific quantity of 

emissions. The total number of allowances created are equal to, 

and constitute, the emissions budget or the aggregated emissions 

limit expressed in terms of short tons of emissions. The EPA is 

proposing that allowances be issued in short tons for the 

federal plan.

Each facility with affected EGUs in the program must 

surrender allowances equal in number to the quantity of the

emissions of its affected EGUs during the compliance period. A

facility with affected EGUs may buy allowances from, or transfer 

or sell allowances to, other affected EGUs or other entities 

that participate in the market. A mass-based trading program 
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provides sources with great flexibility in choosing compliance 

strategies.

In the proposed mass-based trading program for the federal 

plan, the aggregate emissions limit for a state is its statewide 

mass-based emission goal (or “mass goal”) as finalized in the 

Clean Power Plan EGs. The proposed approach to linking states 

for interstate allowance trading is detailed in section III.A.1

of this preamble; in an interstate trading program the aggregate 

emissions limit is the sum of the mass goals for the covered 

states. 

The EPA believes that a broad trading region provides 

greater opportunities for cost-effective implementation of 

controls compared to a smaller region. Therefore, the agency 

proposes that an affected EGU in any state covered by the 

proposed mass-based trading federal plan may use for compliance 

an allowance distributed in any other state covered by the massbased trading federal plan. The EPA also proposes to provide for 

allowance trading between affected EGUs and other entities in

states with approved mass-based-trading state plans that meet 

the conditions specified in section III.A.1 of this preamble, 

above, and affected EGUs and other entities in any state covered 

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 
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assures the specified emissions outcome while maximizing 

compliance flexibility available to individual affected EGUs. 

Further, allowance banking in such a program creates an 

incentive to make reductions earlier than required. Mass-based 

trading programs are relatively simple to operate, which reduces 

administrative time and cost. Additionally, to inform the massbased trading approach proposed here, the EPA draws upon more 

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

including the ARP SO2 trading program, the NOX Budget Trading 

Program, CAIR, and CSAPR.

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.
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Each allowance would authorize the emission of one short 

ton of CO2 during the compliance period applicable to the 

allowance’s vintage year or a later compliance period. The 

proposed approach to distribute allowances, including three 

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

this preamble, below.

After each compliance period, an affected EGU would 

surrender for compliance an amount of allowances equal to its 

emissions during the course of the compliance period. See 

section V.C of this preamble for the proposed length of the 

multi-year compliance periods. Allowances could be transferred,

bought, sold, or banked (carried over for future use) and any 

party could participate in the allowance market. The EPA is not 

proposing allowance “borrowing” (i.e., the bringing forward of 

future-period allowances for use in an earlier period); the 

multi-year compliance periods inherently provide the flexibility 

to schedule relatively greater emission reductions for later 

years within each period, as discussed further in section V.C of 

this preamble. In the proposed mass-based trading program, the 

emission standard applied to individual affected EGUs is the 

requirement to surrender emission allowances equal to reported 

emissions for each compliance period.

The EPA also proposes that a state may choose to replace 

the federal-plan allowance-distribution provisions with its own 
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allowance-distribution provisions (i.e., to determine the 

distribution of allowances for its EGUs or other entities) using 

a state allowance-distribution methodology. State allowance 

distribution can have important advantages, because it allows a 

state to design and shape allowance allocation to its specific 

goals and characteristics, and because states may have 

additional flexibility on allocation approaches, including 

auctions. See section V.E of this preamble for further 

discussion of the proposed approach for state-determined 

allowance-distribution methodologies.

This proposed requirement to hold and surrender allowances 

equal to emissions for each compliance period would apply to all 

reported emissions from a facility’s affected EGUs including any 

emissions from co-fired biomass if biomass is included as an 

eligible measure. Section IV.C.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 qualified 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 
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affected EGU would need to hold allowances equal to its 

emissions less the emissions attributed to the co-fired 

qualified biomass; such an approach would reduce the number of 

allowances the affected EGU would need to hold to demonstrate 

compliance. The EPA requests comment on this approach.

B. Statewide Mass-based Emissions Goals

In the Clean Power Plan EGs the EPA established statewide 

mass-based emission goals (“mass goals”) for all states that are 

equivalent to the rate-based goals. As discussed in section V.C

of this preamble, below, the EPA proposes to implement the massbased trading program with multi-year compliance periods that 

are consistent with the compliance timing provisions in the 

Clean Power Plan EGs, i.e., two 3-year compliance periods 

followed by a 2-year compliance period in the Interim Period, 

and successive 2-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 
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Plan EGs, of each state’s mass goals. The mass goals are 

provided for convenience in Table 8of this preamble.

Table 8. Statewide Mass-Based Emission Goals (“Mass Goals”)

(Short Tons)

State

Interim period

Final 

period

Step 1

2022-2024

Step 2

2025-2027

Step 3

2028-2029

2030-2031

and 

thereafter

Alabama 66,164,470 60,918,973 58,215,989 56,880,474

Arizona 35,189,232 32,371,942 30,906,226 30,170,750

Arkansas 36,032,671 32,953,521 31,253,744 30,322,632

California 53,500,107 50,080,840 48,736,877 48,410,120

Colorado 35,785,322 32,654,483 30,891,824 29,900,397

Connecticut 7,555,787 7,108,466 6,955,080 6,941,523

Delaware 5,348,363 4,963,102 4,784,280 4,711,825

Florida 119,380,477 110,754,683 106,736,177 105,094,704

Georgia 54,257,931 49,855,082 47,534,817 46,346,846

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
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Mississippi 28,940,675 26,790,683 25,756,215 25,304,337

Missouri 67,312,915 61,158,279 57,570,942 55,462,884

Montana 13,776,601 12,500,563 11,749,574 11,303,107

Nebraska 22,246,365 20,192,820 18,987,285 18,272,739

Nevada 15,076,534 14,072,636 13,652,612 13,523,584

New Hampshire 4,461,569 4,162,981 4,037,142 3,997,579

New Jersey 18,241,502 17,107,548 16,681,949 16,599,745

New Mexico 14,789,981 13,514,670 12,805,266 12,412,602

New York 35,493,488 32,932,763 31,741,940 31,257,429

North Carolina 60,975,831 55,749,239 52,856,495 51,266,234

North Dakota 25,453,173 23,095,610 21,708,108 20,883,232

Ohio 88,512,313 80,704,944 76,280,168 73,769,806

Oklahoma 47,577,611 43,665,021 41,577,379 40,488,199

Oregon 9,097,720 8,477,658 8,209,589 8,118,654

Pennsylvania 106,082,757 97,204,723 92,392,088 89,822,308

Rhode Island 3,811,632 3,592,937 3,522,686 3,522,225

South Carolina 31,025,518 28,336,836 26,834,962 25,998,968

South Dakota 4,231,184 3,862,401 3,655,422 3,539,481

Tennessee 34,118,301 31,079,178 29,343,221 28,348,396

Texas 221,613,296 203,728,060 194,351,330 189,588,842

Utah 28,479,805 25,981,970 24,572,858 23,778,193

Virginia 31,290,209 28,990,999 27,898,475 27,433,111

Washington 12,395,697 11,441,137 10,963,576 10,739,172

West Virginia 62,557,024 56,762,771 53,352,666 51,325,342

Wisconsin 33,505,657 30,571,326 28,917,949 27,986,988

Wyoming 38,528,498 34,967,826 32,875,725 31,634,412

C. Compliance Timing and Allowance Banking

The EPA proposes to evaluate compliance (i.e., compare 

emissions from affected EGUs to allowances held by facilities) 

in multi-year periods. A multi-year compliance period provides 

greater flexibility to affected EGUs and reduces administrative 

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 3-year compliance period (2022 through 

2024), a second 3-year compliance period (2025 through 2027), 

and then a 2-year compliance period (2028 and 2029), for the 

Interim Period. As in the EGs, the Final Period would be divided 

into successive 2-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 3 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 GHG mass-based trading programs (i.e.,

emissions budget trading programs) use multi-year compliance 

periods. The RGGI uses 3-year compliance periods, along with 

intervening compliance requirements. The RGGI intervening 

compliance requirement is that sources must hold allowances to 

cover 50 percent of emissions for the first two calendar years 

of each 3-year compliance period; at the end of each 3-year 

compliance period sources must hold allowances to cover 100 
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percent of emissions for the period and allowances already 

deducted for the intervening requirement are subtracted from the 

3-year obligation.90 The California Air Resources Board (CARB) 

Cap-and-Trade Program also uses 3-year compliance periods, along 

with intervening compliance requirements. The CARB intervening 

requirement is to evaluate compliance on 30 percent of each 

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

compliance for the remainder of emissions every 3 years.91 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

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 

 

90 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.

91Overview 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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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 

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 
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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 

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 
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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 massbased trading federal plans, including from how far into the 

future to allow allowances to be borrowed, how inclusion of 

borrowing would affect opportunities for states to take over 
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implementation of the EGs (or implementation of the allowancedistribution provisions in the mass-based trading federal plan), 

how to address removing the extra allowances from circulation 

that would result if borrowed allowances originate in a state 

that subsequently withdraws from the mass-based trading program, 

and on other complexities that borrowing across compliance 

periods would introduce.

The agency proposes to require sources to demonstrate 

compliance, i.e., allowance true-up, on May 1 of the year after 

the last year in the compliance period. For example, if the 

first compliance period comprises the three years 2022, 2023, 

and 2024, then the allowance transfer deadline92 for that first 

compliance period (after which point the EPA would evaluate

compliance) would be on May 1, 2025. The agency also requests 

comment on an earlier or later allowance transfer deadline. 

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

true-up) at the facility level, not at the individual affectedEGU level, in the mass-based trading program. Facility-level 

compliance may ease implementation compared to unit-level 

compliance; each facility has a single compliance account in 

which to hold allowances to cover emissions from all its 

 

92 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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affected EGUs rather than having individual unit-level 

compliance accounts. Fewer accounts may make it easier for the 

designated representatives to manage their allowances. The EPA 

has adopted facility-level compliance in previous emissions 

budget-trading programs including the ARP (70 FR 25162), the 

CAIR (70 FR 25162), and the 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 

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. The 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 
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allocation approach that we intend to use in the event we

implement the federal plan in a state that does not choose to 

determine its own allowance-distribution approach. The EPA is 

requesting comment on all of these, and any other, approaches to 

distribute allowances.

The initial allowance allocation approach that is based on 

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 

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 
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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 

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 historical

data is also consistent with the EPA’s approach to initial 

allowance allocation under previously established mass-based 

trading programs.

The EPA proposes to allocate most CO2 emission allowances to 

existing affected EGUs in each state covered by a final massbased trading federal plan, with set-asides for a portion of 

allowances (discussed in more detail below). For each compliance

period, the agency would distribute CO2 allowances in each 
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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 3 years long, the EPA would 

aggregate and distribute allowances for all 3 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. For each year of the program, the agency 

proposes to allocate most of the allowances directly to affected 

EGUs using a historic-generation based approach. The EPA is also 

proposing three set-asides of allowances, which are detailed 

below.

Although the EPA cannot anticipate the future EGU-level 

pattern of emissions, it is possible to consider potential 

future emission patterns at the source subcategory level. In 

developing the Clean Power Plan EGs, the agency conducted 

analysis of emission reduction potential in the two affected EGU 

source subcategories, i.e., electric utility steam generating 

units (steam generating units) and NGCC units. With that 

analysis as a basis, the EPA is requesting comment on an 

alternative allocation approach that would first divide the 

total number of allowances from each state’s mass goal into 

source subcategories based on analysis done in developing the 

source category-specific CO2 emissions performance rates 
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promulgated in the EGs and then allocate to affected EGUs within 

each category based on shares of historic generation. This 

alternative is described later in this section.

The EPA recognizes that states may prefer different 

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 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.93. 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 

 

93 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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proposed process for a state to replace federal-plan allowancedistribution provisions with its own allowance-distribution 

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, three proposed allowance set-asides, 

allocations to units that change status, and the proposed 

approach for states to replace federal-plan allocation

provisions with their own allowance-distribution approaches. In 

addition, we request comment on alternative allowance 

distribution approaches – such as auctioning or allocations to 

load-serving entities – that the EPA or states might adopt. The 

EPA requests comment on all of these aspects of allowance 

distribution.

1. Proposed Allocation Approach and Alternatives

The EPA proposes to allocate most of the CO2 allowances in 

the mass-based trading program to affected EGUs based on 

historic generation (output) data. The EPA also proposes three 

allowance set-asides. The first would set aside a portion of 

allowances in each state from the first compliance period only; 

this set-aside is for a proposed Clean Energy Incentive Program 

that is detailed in section V.D.4 of this preamble. The second 

would set aside a portion of allowances in each compliance 
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period except for the first period; the EPA proposes to 

distribute allowances from this set-aside to affected EGUs via 

an updating output-based approach as detailed in section V.D.3

of this preamble). The third would set aside 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 set-aside. This set-aside would 

be implemented in all compliance periods.

This section describes the proposed historic-generationbased approach that the agency would use to allocate all 

allowances except for the set-aside allowances. The EPA is 

proposing affected-EGU-level allocations (based on available 

data) in every state. Further detail on this proposed allocation 

approach is provided in the Allowance Allocation Proposed Rule 

TSD in the docket. The affected-EGU-level allocations resulting 

from this proposed historic-generation-based approach are 

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 set-
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asides94) to individual affected EGUs based on each affected 

EGU’s share of the state’s historic generation, using 2010 

through 2012 data. The calculation steps for this proposed 

historic-generation–based allocation approach are as follows:

(1) For each unit in the list of likely affected EGUs 

in each state, identify annual net generation values 

for the historic period of 2010 through 2012 

(reflecting 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.95 (See step 2, below, for how zero 

values would be treated in the calculations.)

The EPA proposes to use a 3-year historic period

(i.e., 2010 through 2012) to reflect unit-level 

operations over time. In the Clean Power Plan EGs, the 

EPA identified a reasonable basis for using aggregate 

data at the regional level largely based on the most 

recent data year (in that case, 2012) to inform the 

establishment of category-wide EGs (as opposed to 

individual, unit-specific parameters). As a distinct 

matter, in this context the EPA is considering data at 

the unit level to inform unit-specific initial 

allowance allocations; notwithstanding that these 

allowance allocations do not impose any unit-level 

compliance requirements in and of themselves, the EPA 

finds it reasonable to consider a multi-year data 

period to inform unit-level initial allocations in 

 

94 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.

95 The EPA proposes that for affected EGUs that were under construction and 

began operation during 2012 or after 2012 (and thus don’t have a full year of 

generation data from the 2010 through 2012 period), the allocation 

calculations be based on the same 2012 generation estimate as the agency used 

in the Clean Power Plan EGs for the goal-setting calculations. That is, the 

EPA proposes to estimate 2012 generation for such units based on a unit’s net 

summer capacity and assuming a 55 percent capacity factor for gas units and a 

60 percent capacity factor for steam units.
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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.

(5) Multiply each affected EGU’s share of the state’s total 

average historic generation by the historic-generationallocation portion of the state’s mass goal (i.e., the state’s 

mass goal minus the set-asides) to determine that affected EGU’s 

allocation.

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

reasons:

• The agency believes that the proposed 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 
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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 methodology. The proposed calculation 

approach is described further below and in the Allowance 

Allocation Proposed Rule TSD in the docket. The historicdata methodology is described in the CO2 Emission 

Performance Rate and Goal Computation TSD 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 EIA on 

forms EIA-860 and EIA-923. The EPA believes these are the 

best data available to the agency at the time of this 

proposed rule for calculating affected-EGU-level 

allocations.

• Allocating based on historic data (as opposed to data not 

yet reported) allows for the distribution of allowances 

prior to the start of the program, which can facilitate

compliance planning.

The proposed approach is transparent, based on reliable 

data, and, like the approaches used in the NOX SIP Call, the ARP, 

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

agency believes that it is appropriate to use a historicgeneration-based allocation methodology in this proposed rule.

The EPA also requests comment on a historic-data approach based 

on historic emissions.

The proposed historic-data-based allocations approach would 

not generally affect the ultimate pattern of generation across

individual power plants, as compared to other methods of 

allocation. The combination of plants, and their contributing 
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generation, that will be used to meet a particular demand for 

electric power will be based on the relative efficiency (cost of 

production) of available plants. The relevant measure of this 

efficiency is the marginal cost of generation, which for a 

particular power plant would be the sum of the cost of 

additional fuel to generate an additional MWh, additional 

maintenance costs to increase output by an additional MWh, and 

costs associated with the additional emissions that result from 

generating an additional MWh. In a mass-based trading program, 

additional emissions must be covered by additional allowances, 

so the cost of emitting is the price of the allowances that must 

be consumed to authorize those emissions. These emissionsrelated costs of electricity production are the same regardless 

of whether the allowances used to cover those emissions were 

initially allocated to the user or whether they were acquired 

subsequently in the marketplace.

The same concept applies to any other cost of electricity 

production. For example, a coal-fired EGUs 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 
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emissions at units because the use of any tradable allowance has 

an opportunity cost – a firm loses the opportunity of selling an 

unneeded allowance when it emits an additional ton. Because a 

firm loses the opportunity of selling an unneeded allowance when 

it emits an additional ton, even the emission of a ton covered 

by a “free” allowance causes the generator to incur the cost of 

emissions based on the market price of allowances the owner must 

forgo by emitting that ton and using that allowance. 

The proposed historic-data based allocation approach would 

not be expected to have any effect on freely competitive 

electricity markets, because the marginal cost of emitting under 

the mass-based trading program is determined by the level of the 

overarching mass goals and is not affected by the distribution 

of the underlying allowances. This marginal cost of emitting is 

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, 
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for the reasons discussed in the above paragraphs, allowance 

allocations that do not change based on future activity (such as 

allocations under the proposed historic-generation based 

approach) do not affect the distribution of emissions under the 

program. This proposed rule is expected to achieve significant 

emission reductions across the electric power sector; see 

section IX of this preamble for discussion of anticipated broad 

benefits to communities.

In addition to the proposed historic-data-based allocations 

approach, the EPA also requests comment on other allocation 

approaches. One alternative approach on which the agency 

requests comment is similar to the proposed approach in that it 

allocates allowances based on historic generation. However, this 

alternative approach would divide the total number of allowances 

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

EGU source categories – based on analysis done in developing the 

source category-specific CO2 emissions performance rates 

promulgated in the Clean Power Plan EGs – before determining 

unit-level allocations. The EPA requests comment on this 

alternative approach because dividing the allowances in a state 

by source category in this manner may result in an initial 

distribution of allowances that would be closer at the sourcecategory level to the future category-level pattern of 

emissions, and thus to allowances ultimately used, than the 
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proposed approach. To the extent that this category-level 

division of allowances is a reasonable proxy for the future 

category-level emissions pattern under the program, this 

approach may reduce wealth transfer between parties that occurs 

as a consequence of a less-anticipatory initial allocation 

procedure. The EPA cannot observe in advance the future 

affected-EGU-level pattern of emissions.

In this alternative approach, for each state the EPA would 

multiply historic steam-generating-unit generation by the steamgenerating-unit source category-specific CO2 emissions 

performance rate, and multiply historic NGCC-unit generation by 

the NGCC-unit source category-specific CO2 emissions performance 

rate. The EPA would do these calculations for each of the 

compliance periods in the Interim Period using the glide path 

interim performance rates, and for the Final Period using the 

final performance rates. These performance rates are shown in 

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

established the source category-specific emissions performance 

rates in the Clean Power Plan EGs (see section VI 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) into affected-EGU source 

categories in proportion to the values resulting from the above 
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calculation. The EPA would then allocate the steam–generatingunit portion of the allowances to individual SGUs using the same 

historic-generation based approach described above, and would 

also allocate the NGCC-unit portion of the allowances to 

individual NGCC units using the historic-generation based 

approach.

The EPA notes that there are multiple approaches that 

policymakers may use to distribute allowances, beyond the 

proposed or alternative allocation approaches we included in 

this proposed rule. Examples of other allocation approaches 

include allocating based on historic heat input (fuel) or 

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.96 Alternatively, 

allocations could be distributed based on projected or observed

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

 

96 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 EE

measures intended to help reduce electricity rate impacts and 

overall program costs, as well as targeted investments in low-
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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.97 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 comment on an alternative approach, which 

is allocating a portion of the allowances to load-serving 

entities (LSEs) rather than to affected EGUs. LSEs are the 

entities responsible for delivering power to retail consumers. 

Allocation to LSEs can help mitigate bill impacts on 

electricity consumers when applied in concert with certain 

additional design features. In particular, if LSEs commit and/or 

are required to pass through to ratepayers the value from their 

 

97 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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selling of the allocated allowances, this approach can mitigate 

the impact of electricity bill increases on consumers that might 

otherwise result from application of the federal plan. As 

described in the Allowance Allocation TSD, this type of approach 

can also help to avoid or mitigate the potential for windfall 

profits for affected EGUs. The EPA could apply this approach by 

conditioning the receipt of allowances by LSEs on the pass 

through to consumers of any allowance value if necessary.

The EPA requests comment on the design and utility of 

allocating allowances to LSEs to help mitigate electricity price 

impacts. In particular, the EPA requests comment on options to 

establish conditions requiring pass through of allowance value 

and verification of such pass-through, whether it would be 

appropriate to identify any conditions related to equitable 

distribution of allowance value among ratepayer categories, as 

well as the EPA’s legal authority to apply any such conditions.

The EPA requests comment on the additional design aspects 

of any potential allocation to LSEs, including but not limited 

to the following questions: In particular, what metric should 

provide the basis for LSE allocation, e.g., electricity demand

served by the LSE, population served by the LSE, emissions 

associated with generation serving the LSE, or some other 

metric. If emissions are used as the basis for such allocation, 

what approach should be taken: on a historic basis or a 
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continually updated basis, on the basis of estimated emissions 

for the relevant region or some other basis, and using what data 

to calculate such emissions. Also, the EPA requests comment on 

the form by which LSEs may distribute the allowance value to 

rate-payers, e.g. as a fixed amount, through reduced rates, etc. 

Finally, the EPA requests comment on what share of the total 

number of allowances should be distributed to LSEs and what 

monitoring and reporting requirements may be necessary to 

support an effective program.

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

that divides total allowances from a mass goal into source 

subcategories before allocating to individual affected EGUs

within each source category based on historic generation, and on 

the other alternative approaches described in this section. The 

EPA also requests comment on allocating allowances to all 

generation in a state (including non-emitting generation) using 

a historic-generation based approach. The agency also requests 

comment on the proposed allowance set-asides, which are detailed 

below. The agency requests comment on allocation approaches that 

may minimize the impact of this proposed rule on small entities. 

The EPA also requests comment on any other approaches to 

distribute allowances. The agency notes that we propose to 

provide that any state may choose to replace the federal-plan 
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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 as part of the program, the allocation methodology 

must address leakage to new fossil fuel-fired sources.

2. Timing of Allowance Recordation

The proposed historic-data-based allocation approach –

which the EPA proposes to use to allocate all of the allowances 

in each state except for the set-aside allowances – is a onetime determination that is not updated. The allocations 

resulting from this approach would be determined prior to the 

start of the program. The EPA proposes to record the historicdata based allowances for each compliance period in source 

accounts prior to the start of each compliance period, and to 

record allowances for one compliance period at a time. Recording 

allowances prior to the start of a compliance period provides 

certainty to affected EGUs of their allocations in advance of 

when the allowances are needed for compliance and can facilitate 

long-term planning. Recording allowances for one compliance 

period at a time provides flexibility for a state to replace the 

federal plan with its own plan in a timely way. As discussed in 
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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 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 7 months prior to 

the start of each compliance period. For example, if compliance 

periods are 3 years long and the first compliance period

comprises the years 2022, 2023, and 2024, the EPA would record 

allowances for 2022, 2023, and 2024 by June 1, 2021. The EPA 

requests comment on the proposed approach of recording 

allowances 7 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 
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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 

have addressed the risk of leakage to new unaffected units, as 

specified below.98

The final 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 rate-based 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 goal ensures sufficient 

 

98 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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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.

As noted in the EG, if a state were to adopt allowance setaside 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 
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EGUs. This is because the EPA does not have authority to extend 

regulation of and federal enforceability to new fossil fuelfired 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 based upon criteria designed 

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.99 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 

 

99 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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following are examples of set-asides and similar programs used 

in other federal air quality rules, and in state-based GHG 

regulatory programs.

The EPA has previously established set-asides of emissions 

allowances in FIPs under CAA section 110. For example, in the 

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.100 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 an initial allowance

allocation out of the new unit set-aside, the EPA chose the 

latter. 

 

100 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 ARP 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.”101 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 proposal seeks to minimize the 

administrative burden associated with participation in this 

rule’s proposed set-asides.

In the NOX SIP Call, the EPA encouraged states to “consider 

including energy efficiency and renewables as a strategy in 

 

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

EPA 430-R-94-010 (Nov. 1994).
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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.102 In general, the EPA believes its experience and those 

of the states with these set-aside programs support the view 

that they are an effective means to spur clean energy projects, 

 

102 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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which in turn we believe can help to reduce the risk of leakage 

in this instance.103

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. Second, the EPA proposes a set-aside for electricity 

generation from qualifying renewables. This set-aside also 

addresses the potential for leakage to new sources, as increased 

RE capacity can serve electricity demand in place of new 

sources. The EPA also solicits comment on other set-aside 

options that could address 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 setasides, the requirements for the process of distribution, 

 

103 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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eligibility requirements for receiving set-aside allowances, the 

proposed process for redistribution of undistributed allowances 

from each set-aside, and any other appropriate set-asides.

a. Set-asides for Output-based Allocation

The EPA is proposing a set-aside approach referred to as 

output-based allocation, which provides targeted allocations of 

a limited portion of allowances to existing NGCC units as a 

means of mitigating leakage. The EPA believes that this proposed 

set-aside would reduce incentives for generation to shift away 

from EGUs covered under mass-based plans to new unaffected EGUs. 

We seek comment on all aspects of this proposal and its 

underlying rationale.

Under the output-based allocation approach we are 

proposing, beginning with the second compliance period, a 

portion of the total allowances within each mass-based federal 

plan state would be allocated to existing NGCC units based, in 

part, on their level of electricity generation in the previous 

compliance period. Each eligible EGU would get a larger 

allowance allocation from this set-aside if it generates more,

such that owner/operators of eligible EGUs will have an 

incentive to generate more in order to receive more allowances. 

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 
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manner designed to align the generation incentives for eligible

EGUs in mass-based states with new emitting EGUs that are not 

subject to a mass-based limit, mitigating emissions leakage. 

The EPA is 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 timing of the setaside’s allocation procedure, the allocation rate(s), and the 

size of the set-aside. The EPA also invites comment on what 

other parameters may be relevant for design of an appropriate 

output-based 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 EGs

receive output-based allocation from the set-aside. 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 

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 a mass goal. As noted in the discussion 

of the allocation rate below, new combustion turbines (i.e., 
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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 subject to a mass goal and otherwise similar 

new stationary combustion turbines that are not subject to a 

mass goal is likely one of the most salient deviations in 

production incentives to address.

The EPA also requests comment on extending output-based 

allocation from this set-aside to affected SGUs. Output-based 

allocation for SGUs may increase generation subject to the mass 

limit, leading to reduced generation and emissions from new 

emitting sources. However, the EPA does not propose this 

approach because it is not as effective as output-based 

allocation to NGCC units. This is because output-based 

allocation to SGUs would incentivize generation from relatively 

high-emitting EGUs, which would likely increase allowance prices 

as other emission reductions are made to respect the overarching 

mass limit. This approach would thus strongly counteract the 

intended effect of lowering the production cost from sources 

subject to the proposed mass-based federal plan (compared to 

emitting sources not subject to the plan). The EPA also requests 

comment on extending output-based allocation from this set-aside 

to zero-emitting generators (including both renewable and 

nuclear generation), and how the design of the OBA set-aside for 
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such generators would differ relative to the NGCC approach 

(e.g., the amount of allowances earned per MWh, the capacityfactor threshold, the size of the total set-aside).

The EPA also proposes that this approach be targeted 

towards marginal generation that may not have otherwise occurred 

absent this set-aside, by providing allocations under this setaside only to eligible EGUs that exceed a 50 percent capacity 

factor on a net basis over the compliance period, and only for 

the portion of their generation that exceeds that capacity 

factor.104

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; 

 

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

allocation is zero up until this average capacity factor.
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eligible generation that occurs during the first compliance 

period would be recognized through this set-aside with 

allowances of vintage years from the second compliance period 

(2025-2027).

The EPA is proposing this lagged accounting procedure 

because the amount and location of eligible generation in any 

given compliance period remains uncertain until the compliance 

period has ended and the relevant data has been reported and 

verified. Without this lagged accounting procedure, the EPA 

would have to withhold an amount of allowances for this setaside from certain vintage years even as the corresponding 

compliance period was already underway. Given the size of this 

proposed OBA set-aside in certain states, the EPA believes it 

would be more advantageous for affected EGUs to know in advance

how many allowances they will be allocated in a given period, 

inclusive of allowances allocated through this OBA set-aside.105

The EPA requests comment on options for the allocation rate 

under this approach. The allocation rate is the number of 

allowances, in an amount equal to a specific amount of 

emissions, that the affected EGU receives per one net MWh of 

generation eligible for the set-aside. The EPA proposes to set

 

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

net basis) for new NGCC units under 111(b), in order to align 

the generation incentives across EGUs eligible for the set-aside 

and the type of new emitting source that would generate more 

absent this set-aside. Specifically, an additional MWh of 

eligible generation would earn the affected EGU allowances equal 

to the level of emissions permitted per MWh of net generation 

under the 111(b) new source standard, which is 1,030 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 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.106

The EPA proposes to use net summer capacity as reported to EIA. 

 

106 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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In the alternative, the EPA proposes to require that NGCC units 

report net summer capacity directly to 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 (see section 

V.H of this preamble). The EPA notes that the EIA net summer 

capacity data is reported at the generator level; if we add this 

data point to the certificate of registration it would be 

reported at the affected-EGU level, which would facilitate 

calculation of capacity factors. The EPA also requests comment 

on whether the “maximum load value,” which is a parameter that 

EGUs report to the EPA in their monitoring plans, is a 

reasonable proxy for EGU-level net summer capacity for these 

calculations. The EPA also requests comment on an alternative 

approach of basing the capacity-factor calculation on nameplate 

capacity instead of net summer capacity, or other approaches to 

the calculation.

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

set-aside once, before the start of the program, and not to 

change the size thereafter. The EPA proposes to determine the

size of the set-aside assuming that it would incentivize 

existing NGCC to increase utilization to a 60 percent capacity 

factor. The assumed 60 percent capacity factor offers a way to

limit the size of this set-aside, which allows the remainder of 

the allowances in a given compliance period to be allocated 
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through the historic-generation approach (as detailed above) and 

the other proposed set-asides (as detailed below). Furthermore, 

limiting the size of the set-aside avoids the risk of 

incentivizing too much generation from eligible sources, as 

discussed further in the Allowance Allocation Proposed Rule TSD.

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

set-aside using 2012 baseline data from the Clean Power Plan 

EGs.107 The EPA would calculate the size of the set-aside as 10 

percent of the NGCC capacity in the state108 multiplied by the 

hours in a year multiplied by the allocation rate for the setaside. The EPA takes comment on the proposed capacity data used 

as the basis for determining the size of the output-based setaside, and alternative sources of capacity data that may be used 

for determining its size. 

The set-asides resulting from this proposed approach are 

shown in Table 9 of this preamble. The set-asides in the table 

would apply to every compliance period except for the first 

compliance period for which there would be no output-based setaside. Although the size of the set-aside would remain the same 

for each compliance period, as the mass goals decrease with each

 

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

Rule.

108 The sum of net summer capacity for affected NGCC units in the 2012 

baseline for the Clean Power Plan EGs (CO2 Emission Performance Rate and Goal 

Computation TSD for the CPP Final Rule).
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step in the Interim Period and to the Final Period, the setasides would constitute an increasing share of a state’s mass 

goal. The Allowance Allocation Proposed Rule TSD further details

the proposed approach to determine the size of the set-aside. 

The EPA requests comment on a potential limit for the size of 

the set-aside in a compliance period based on a percentage of 

the state’s total allowances for the compliance period.

Table 9. Proposed Size of Output-Based Set-Aside for the Second 

Compliance Period and Later(Short Tons)

State Allowances in outputbased set-aside

Alabama 4,185,496

Arizona 4,197,813

Arkansas 2,102,538

California 8,458,604

Colorado 1,348,187

Connecticut 1,090,811

Delaware 649,190

Florida 12,102,688

Georgia 3,563,104

Idaho 246,638

Illinois 1,598,615

Indiana 1,106,150

Iowa 492,510

Kansas 62,257

Kentucky 288,730

Lands of the Fort Mojave Tribe 248,127

Lands of the Navajo Nation 0

Lands of the Uintah and Ouray Reservation 0

Louisiana 2,207,879

Maine 563,925

Maryland 103,762

Massachusetts 2,439,991

Michigan 2,105,786

Minnesota 909,724

Mississippi 3,132,671
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Missouri 815,210

Montana 0

Nebraska 144,635

Nevada 2,326,529

New Hampshire 542,721

New Jersey 3,413,100

New Mexico 627,085

New York 3,815,381

North Carolina 2,120,178

North Dakota 0

Ohio 1,757,326

Oklahoma 3,121,167

Oregon 1,291,027

Pennsylvania 4,392,931

Rhode Island 778,307

South Carolina 1,029,366

South Dakota 130,831

Tennessee 632,949

Texas 15,990,657

Utah 825,586

Virginia 3,011,811

Washington 1,383,060

West Virginia 0

Wisconsin 1,181,175

Wyoming 45,114

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. 
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The EPA proposes that if the number of allowances allocated 

from the set-aside is less than the size of this set-aside, then 

the remaining allowances would be distributed to all affected 

EGUs using the historic-generation based-approach described 

above.

The EPA proposes to provide notice of the capacity and 

generation data used to calculate allocations from the setaside, and the resulting allocations, by August 1 of the first 

year in each compliance period, e.g., by August 1, 2025 for the 

compliance period that commences in 2025 (and based on the data 

from the prior compliance period). The agency proposes to 

provide 30 days for comment on the data and allocations, until 

August 31, and to provide notice of the final set-aside 

allocations by November 1 of the same year and record the 

allocations in the source accounts at that time. The EPA 

requests comment on other approaches to providing notice of the 

data and allocations.

The EPA requests comment on all aspects of the proposed 

approach to calculate output-based set-aside allocations. 

Further details are in the Allowance Allocation Proposed Rule 

TSD in the docket.

b. Set-asides for Renewable Energy Projects 

The EPA proposes to provide a set-aside of allowances for 

distribution to RE in each state covered by the proposed mass-
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based federal plan, and is also proposed for the mass-based 

model rule. The agency is also taking comment on whether 

distribution should extend to demand-side energy efficiency (DSEE) and CHP projects. Under this program, the EPA would reserve 

a percentage of each state’s allowances in a set-aside account 

for each state. Developers of RE projects could apply to receive 

set-aside allowances based on the projected generation from 

eligible RE capacity.

This set-aside is expected to address concerns regarding 

leakage by lowering the marginal cost of production of the 

incented clean energy technologies within the state. This will 

make RE more competitive against new sources, reducing the 

potential for leakage to new sources. 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.

In the context of the proposed federal plan, the EPA is 

proposing that it would create a unique set-aside for each state 

covered by a mass-based federal plan. Under a model rule, the 

state would create this set-aside. The allowances in each setaside would be reserved from each vintage of the assigned mass 

goal to that state prior to allocation of allowances to sources. 

The EPA is proposing that 5 percent of allowances will be 
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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 Allowance Allocation 

Proposed Rule TSD. We note that, under the proposed framework, 

these allowances would be available to affected EGUs either in 

the marketplace or through subsequent distribution of unclaimed 

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

does not affect the overall stringency of the program.

In section V.D.5 of this preamble, below, the EPA is 

proposing that the size of the RE set-asides may grow over time 

as certain units shift out of the program.

We are proposing, as part of the mass-based federal plan 

and model 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 
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preamble and section VIII.K of the final 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 ARP set-aside, and would limit

the entities eligible to receive set-aside allowances to 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 

both the federal plan and model rule. Eligible RE projects must 

be located in the mass-based state for which the set-aside has 

been designated. The agency invites comment on whether capacity 

outside the state should be recognized, and how that could be 

implemented. The EPA also proposes that the generation for which 

an entity receives allowances from the set-aside would not be 

eligible for ERC issuance in rate-based states. 

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

proposing that the same RE measures are eligible to receive setaside allowances under a mass-based federal plan as would be 

eligible for ERC issuance under a rate-based federal plan and 

the model rule. Specifically, the following RE measures are 

eligible: on-shore wind, solar, geothermal power, and 
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hydropower. The RE measure must also have the capacity to 

provide data quantified by a revenue-quality meter, 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 setaside allowances, as we do not think a set-aside used as an

incentive for incremental nuclear capacity is a useful way to 

address leakage to new sources during the performance period, 

due to unique costs and development timelines for incremental 

nuclear power. All other proposed aspects of the RE eligible 

measure types described in section IV.C of this preamble and the 

requests for comment included within that section also apply in 

the mass-based set-aside context for both the proposed massbased federal plan and the proposed mass-based model rule. For 

example, we are requesting comment on the inclusion of other RE 

measures, incremental nuclear, demand-side EE measures, CHP and 

any other emission 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-
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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 treatment requirements offered 

for comment in section IV.C.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 MWh generation for an RE project. The EPA must 

approve the documentation of eligibility and the projection of 

MWh 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 
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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 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 improve the EM &V process by 

making the eligible resources more accountable. The EPA requests 

comment on what documentation would be required if other measure 

types were considered eligible to receive set-aside allowances.

We propose that the same process for approval of projects be 

applied in a model rule, with the state taking the approving 

role instead of EPA.

The EM&V requirements for the mass-based set-aside differ 

from those for rate-based ERC issuance, particularly because it 

is based upon projections provided prior to generation rather 

metered data provided after the generation occurs (though we are 

proposing that the projections will be checked against ex-post 

metered data). The projection method enables the distribution of 

set-aside allowances prior to the year during which the 
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generation occurs. The EPA feels this still provides sufficient 

rigor because the set-aside does not directly affect program 

stringency. The reason that stringency is not affected is 

because of key differences between issuance of credits and 

distribution of set-aside allowances. Under rate-based 

implementation, each decision to issue an ERC based on a 

quantification of RE generation affects the ultimate amount of 

allowable CO2 emissions, because the number of ERCs is determined 

by the amount of MWhs approved as eligible for ERC issuance and 

the ERC does not exist until the issuance decision is made. Thus 

the amount of ERCs that are issued can affect the stringency of 

the rule. As a result, the EPA has laid out specific 

requirements (including EM&V procedures) in the final CPP, and 

in this proposed federal plan and model rule, to assure the 

environmental reliability of measures qualifying for ERC 

recognition under rate-based implementation. In contrast, any 

decision to recognize RE with set-aside allowance allocations 

under a mass-based approach does not affect the validity of the 

allowance itself and does not affect the CO2 emissions outcome 

because the ultimate amount of allowable CO2 emissions is 

determined by the total number of allowances initially created 

(regardless of how they are distributed). As a result, while the 

EPA believes it is reasonable to consider a minimum set of 

qualifications for recognizing RE through these allowance set-
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asides to assure that the RE generation that is incented is 

actually produced, the EPA does not believe the overall 

integrity of mass-based implementation is significantly affected 

by the robustness of whatever eligibility requirements the EPA 

ultimately sets for RE recognition through allocation from these 

set-asides. This being said, the agency is proposing to require 

robust demonstrations of the eligibility and EM&V projections 

for RE generation submitted for the set-aside, demonstrations 

that are based in the best practices of existing programs. This 

is necessary to assure the delivery of RE as a result of the 

set-aside.

The EPA proposes that the projections of MWh 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 set-aside project 

application, and that application must be approved by a thirdparty verifier. The EPA invites comment on these proposed 

requirements for projections. We also take comment on whether 
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set-asides should be distributed proportional to actual MWh

provided by the installation in a prior year or compliance 

period, or another form of historical generation data. This type 

of allocation method could also be similar to the structure 

proposed for the OBA set-aside. We propose that the same 

projection-based distribution basis be applied in a model rule, 

with the state taking the approving role instead of EPA.

The EPA is proposing the following process for distribution 

of RE set-aside allowances. Starting prior to the compliance 

period, and going forward through the compliance period, RE 

providers in each state will have an opportunity to apply to the 

EPA or a designated agent to be approved as eligible to receive 

set-aside allowances in their state. This application must 

include all the requirements outlined above, including 

projections of expected MWh of generation. The EPA is proposing 

to accept RE set-aside project applications up to a deadline of 

June 1 in the year prior to the year during which the RE 

generation occurs (the “generation year”). The EPA or its agent 

will review and approve the project as eligible and it will be 

entered into the pool of projects that will receive set-asides

in any compliance period. If approved, the number of projected 

MWh in each generation year will be the basis of the number of 

allowances the provider will receive, as an input to the 

methodology specified below. The providers will have an 
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opportunity to update projections for future generation years, 

these projections must be received by June 1 of the year prior 

to the generation year in question. 

On December 1 of the year prior to each year of the 

compliance period in question, the EPA is proposing to 

distribute allowances from the set-aside to approved providers. 

The agency is proposing to distribute set-aside allowances to 

approved RE providers pro-rata, with the number of allowances 

distributed to each provider according to the percentage of 

total approved RE MWh 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 generation year, RE providers receiving 

allowances will have to provide an M&V report with the MWh of RE 

generation actually produced, to assure that they have met the 

projected level of generation. These M&V reports need to 

document that the generation was by an approved project, and the 

report should be approved by a third party verifier. As 
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discussed in the rate-based approach EM&V section above, these 

data should be readily available from existing metering. The EPA 

requests comment on the process for submitting M&V reports with 

actual generation. 

If the project or program does not reach the MWh projected 

in a particular generation year, the unfulfilled MWh will be 

subtracted from that RE provider’s MWh eligible for the setaside in the next generation year, or multiple years if the 

deficit exceeds the MWhs projected for the upcoming year. If 

this deficit is greater than 10 percent in a particular year, 

the provider will need to provide an explanation of the deficit 

and will be required to reevaluate their projections for future 

years. If such deficits continue through all 3 years of the any

performance period in which they participate, the provider will 

be disqualified from receiving future set-asides for the 

following compliance period. We also take comment on whether a 

provider with continuing deficits should also be disqualified 

from receiving ERCs for some or all of the remaining performance 

periods. The agency requests comment on all of the specified 

aspects of this distribution process.

The EPA is proposing that once allowances have been 

distributed to all approved providers, any remaining allowances 

in the set-aside, such as set-aside allowances designated for 

projects that no longer exist, will be redistributed to affected 
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EGUs in the state in a pro rata fashion on the same distribution 

basis as their initial allocations were made. It is proposed 

that this will occur immediately after the distribution of setaside allowances to eligible RE providers on December 1 of the 

year prior to the generation year in question. The EPA requests 

comment on this approach.

We propose that the same distribution process as outlined 

above be applied in a model rule, with the state taking the 

approving role instead of EPA.

The EPA is also seeking comment, in the context of the 

proposed rate-based federal plan and model rule, on whether a 

portion of this set-aside should be targeted to RE projects that 

benefit low-income communities. This benefit could be in the 

form of MWh provided to the low-income community, financial 

proceeds from the project primarily benefiting the low-income

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 

from the methods that are proposed to apply to other RE 

projects.
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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 2021.109 These early action allowances 

would be drawn from a third set-aside of allowances from the 

 

109 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 

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

energy savings they achieve during 2020 and/or 2021.
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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.110 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 

aside. While the table shows set-asides for every state, the EPA 

proposes to implement this set-aside, according to the amounts 

 

110 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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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 

create an account of “matching” allowances for each state 

participating in the CEIP – regardless of whether a state is 
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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 states111 – which would be 

limited to the equivalent of 300 million short tons of CO2

emissions. Thus, states whose EGUs have greater reduction 

obligations will be eligible to secure a larger proportion of 

the federal allocation upon demonstration of quantified and 

verified MWh of RE generation or demand side-EE savings from 

eligible projects realized in 2020 and/or 2021. The EPA intends 

that a portion of these matching allowances would be reserved 

for eligible wind and solar projects, and a portion would be 

reserved for eligible EE projects implemented in low-income 

communities. The agency recognizes that there have been historic 

economic, logistical and information barriers to implementing EE 

programs in these communities, and therefore believes it is 

appropriate to reserve a portion of the federal pool to 

incentivize investment in these programs. The EPA is requesting 

comment on the size of reserve of matching allowances for 

eligible low-income EE programs as well as for eligible wind and 

 

111 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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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, 2018112 will be distributed to 

those states with approved state plans that include requirements 

for CEIP participation, as well as to those states on whose 

behalf EPA is implementing a federal plan. These allowances will 

be distributed according to the pro rata method outlined above. 

Unused matching allowances that remain in the accounts of states 

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

 

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

CEIP participation in their state plans. 
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the EPA. The EPA seeks comment on whether the number of matching 

allowances available to a state under the mass-based federal 

plan should be limited to a number equal to the number of early 

action allowances included in each federal plan state’s early 

action 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 

any remaining early action set-aside allowances in a state –

after distribution to all eligible projects in the state – to 
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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 

states; (3) the timing of distribution of set-aside and matching 

allowances; (4) the amount of allowances awarded per eligible 
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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

Colorado 2,223,192

Connecticut 69,415

Delaware 138,392

Florida 3,230,248
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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

Virginia 1,386,546

Washington 751,434

West Virginia 3,506,890

Wisconsin 2,393,870
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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 2 consecutive calendar years, the unit 

would continue to receive allocations for a limited number of 

years after it ceases operation, after which the allowances that 

would otherwise have been allocated to that unit would be 

allocated to the RE set-aside for the state in which the retired 

unit is located.113 Continuing allocations to non-operating units 

for a period of time reduces the incentive to keep a unit 

operating simply to avoid losing the allowance allocations for 

that unit (e.g., a unit that would otherwise be retired due to 

age and inefficiency). On the other hand, non-operating units 

are no longer emitting and so do not need allowances. The EPA 

believes that the proposed approach of allocating allowances for 

a specified, but limited, period after a unit ceases operating

is a reasonable middle ground approach. The proposed approach 

also allows the RE set-asides to grow over time.

The EPA proposes to record allowances for each year of a 

multi-year compliance period at once, 7 months prior to the 

start of each compliance period, as discussed above. The agency 

 

113 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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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 

output-based allocations, or to the remaining affected EGUs in 
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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 approach, which would be to 

continue allocations to the retired units. The EPA also requests 

comment on treatment of allocations to units that are in longterm 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 

approach, which would be to continue allocations to the modified 

or reconstructed units.
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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 the state-determined allocation 

approach offers significant advantages and solicits comment on 

how to ease its application by states. This is similar to the 

approach taken in CSAPR and CAIR where the EPA adopted rules
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allowing states to submit SIPs with provisions replacing the 

allowance-distribution provisions in the CSAPR or CAIR FIPs, 

respectively, while remaining in the trading programs under 

those FIPs (76 FR 48208; August 8, 2011, 71 FR 25328; April 28, 

2006). In both CSAPR and CAIR, some states have chosen to 

determine their own allocations under the FIPs. This form of SIP 

that can replace the 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 

allowance-distribution provisions of its choosing. 

The mechanism the agency envisions is in the nature of a 

partial state plan or (for any future changes in a state’s 

allocation methodology) a partial state plan revision. (We 

request comment below on the advantages and disadvantages of 

allowing a state to handle allocations via a delegation of 

federal plan authority.) In general, under the proposed 

approach, the procedural requirements states and the agency must 

follow, including public notice requirements, for the submission 

and approval of state plans, would be required here.

The EPA intends to provide the states with substantial 

flexibility in choosing approaches to distribute their
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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 (see 

sections VII.D and VIII.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 RE 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 address leakage. The EPA proposes that a 

state allowance-distribution 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 
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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 (section VIII.J 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 allowance-distribution 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 methodology may also include other setaside 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 
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include a Clean Energy Incentive Program, as detailed in section 

V.D.4 of this preamble.

Under the proposed approach of providing for states to 

determine their allowance distribution approaches in the federal 

plan mass-based trading program, the affected EGUs in a state 

that submitted a state allowance-distribution methodology, which 

the EPA approved, would participate in the federal plan massbased trading program, but with allowance distribution 

determined by the state instead of by the EPA.

The EPA proposes that a state must submit to the 

Administrator tables specifying the unit-level allowances in an 

electronic format specified by the Administrator and by the 

specified deadlines applicable to each compliance period (see 

Table 11 of this preamble for proposed submission deadlines).

The EPA proposes that a state may submit a state allocation 

methodology for any compliance period, including the first 

compliance period, which would comprise the years 2022, 2023,

and 2024. The EPA proposes that a state submitting a state 

allowance-distribution methodology to modify the federal plan 

allowance-distribution provisions must do so for all years 

within a compliance period (e.g., for all 3 years in a 3-year 

compliance period).

The EPA proposes that, if the state’s allowancedistribution provisions meet certain requirements and the state 
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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 RE 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 allowancedistribution 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 applicable mass goal.114

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 

 

114 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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having the EPA implement the remainder of its allocations.

Additionally, the EPA proposes that a state allowancedistribution methodology must provide for allowances to be 

issued in short tons.

The allocation (or auction) of allowances would be final 

and could not be subject to modification. Additionally, the 

state’s provisions could not change any other provisions of the 

proposed mass-based trading program with regard to the 

allowances (e.g., the deadlines for allocation recordation, or 

requirements for transfer or use of allowances) or any other 

aspect of such trading programs.

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 12 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, 
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the EPA proposes the following deadlines, in Table 11 of this 

preamble, for submission to the agency of state allowancedistribution methodologies and unit-level allowances, and for 

the EPA’s recordation of allowances, for each compliance period.

The EPA would review and approve state allowance-distribution 

methodologies in the 12 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 3 months before 

the proposed deadline for the agency to 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 AllowanceDistribution 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 2-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. 
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The agency anticipates that it can complete the approval process 

relatively quickly for a state allowance-distribution 

methodology due to its narrow scope.

The agency proposes to record the EPA-determined federal 

plan allocations only in the absence of an approved state plan 

or approved state allowance-distribution methodology. The EPA 

proposes to record in source accounts allowances that are 

determined by any state as soon as feasible after approval of a 

state allowance-distribution methodology and submission of the 

unit-level allowance table, and not to wait until the allowance 

recordation deadline to do so.

In section V.D.2 of this preamble, the EPA proposes the 

allowance recordation deadline 7 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 13 months prior to 

the start of the compliance period (i.e., December 1 of the year 

2 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 allowance-distribution 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 
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reasons that the agency proposes that a state may not replace a 

mass-based trading federal plan with a state plan for a future 

compliance period for which allowances have already been 

recorded, as discussed below in section V.F of this preamble.

The agency requests comment on the proposed approach to 

allow states to determine allocations via state allowancedistribution methodologies and replace the federal-plan 

allowance-distribution provisions. The EPA requests comment on 

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 
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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 

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 of 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 3-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, 
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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 

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.
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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 stateplan 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 CSAPR and the 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
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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 

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 

The EPA proposes to establish 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 
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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 mass-based trading 

program. One alternate designated representative could also be 

selected to act on behalf of, and legally bind, the designated 

representative and thus the owners and operators. Because the 

actions of the designated representative and alternate would 

legally bind the owners and operators, the designated 

representative and alternate would have to submit a certificate 

of representation certifying that each was selected by an 

agreement binding on all such owners and operators and was 

authorized to act on their behalf.

The designated representative and alternate would be 

authorized upon receipt by the Administrator of the certificate 

of representation. This document, in a format prescribed by the 

Administrator, would include: specified identifying information 

for the affected EGU and for the designated representative and 

alternate; the name of every owner and operator of the affected 

EGU; and certification language and signatures of the designated 

representative and alternate. All submissions (e.g., monitoring 
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plans, monitoring system certifications, and allowance 

transfers) for an affected EGU would have to be submitted, 

signed, and certified by the designated representative or 

alternate. Further, upon receipt of a complete certificate of 

representation, the Administrator would establish a compliance 

account in the ATCS for each facility with an affected EGU 

involved.

In order to change the designated representative or 

alternate, a new certificate of representation would have to be 

received by the Administrator. A new certificate of 

representation would also have to be submitted to reflect 

changes in the owners and operators of the affected EGU 

involved. However, new owners and operators would be bound by 

the existing certificate of representation even in the absence 

of such a submission.

In addition to the flexibility provided by allowing an 

alternate to act for the designated representative (e.g., in 

circumstances where the designated representative might be 

unavailable), additional flexibility would be provided by 

allowing the designated representative and alternate to delegate 

authority to make electronic submissions on his or her behalf.

The designated representative and alternate could designate 

agents to submit electronically certain specified documents. The 

previously-described requirements for designated representatives 
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and alternates would provide regulated entities with flexibility 

in assigning responsibilities under the mass-based trading 

program, while ensuring accountability by owners and operators 

and simplifying the administration of the proposed mass-based 

trading program. 

2. Allowance Tracking and Compliance System 

The mass-based trading program rules would establish the 

procedures and requirements for using and operating the 

Allowance Tracking and Compliance System (which is the 

electronic data system through which the Administrator would 

handle allowance allocation, holding, transfer, and deduction), 

and for determining compliance with the allowance-holding 

requirements in an efficient and transparent manner. The ATCS 

would also provide the allowance markets with a record of 

ownership of allowances, dates of allowance transfers, buyer and 

seller information, and the serial numbers of allowances 

transferred. Consistent with the approach in prior EPAadministered trading programs, allowance price information would 

not be included in the ATCS. The EPA’s experience is that 

private parties (e.g., brokers) are in a better position to 

obtain and disseminate timely, accurate allowance price 

information than is the EPA. For example, because not all 

allowance transfers are immediately reported to the 

Administrator for recordation, the Administrator would not be 
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able to ensure that any reported price information associated 

with the transfers would reflect current market prices.

3. Compliance and General Accounts 

This section describes two types of Allowance Tracking and 

Compliance system accounts: Compliance accounts, one of which 

the Administrator would establish for each facility with an 

affected EGU upon receipt of the certificate of representation 

for the facility; and general accounts, which could be 

established by any entity upon receipt by the Administrator of 

an application for a general account. A compliance account would 

be the account in which any allowances used by an affected EGU

for compliance with the emissions limitations would have to be 

held. The designated representative and alternate for the 

affected EGU would also be the authorized account representative 

and alternate for the compliance account. Using facility-level, 

rather than EGU-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 
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facility. Facility-level compliance would also be consistent 

with other EPA-administered mass-based trading programs.

General accounts could be used by any person or group for 

holding or trading allowances. However, allowances could not be 

used for compliance with emissions limitations so long as the 

allowances were held in, and not properly and timely transferred 

out of, a general account. To open a general account, a person 

or group would have to submit an application for a general 

account, which would be similar in many ways to a certificate of 

representation. The application would include, in a format 

prescribed by the Administrator: the name and identifying 

information of the individual who would be the authorized 

account representative and of any individual who would be the 

alternate authorized account representative; an identifying name 

for the account; the names of all persons with an ownership 

interest with respect to allowances held in the account; and 

certification language and signatures of the authorized account 

representative and alternate. The authorized account 

representative and alternate would be authorized upon receipt of 

the application by the Administrator. The provisions for 

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 
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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 EGUs for 2022 through 2024. Then, by June 1 of 

the year prior to the beginning of each compliance period, the 

Administrator would record the allowance allocations for the 

proposed mass-based trading program for each year within that 

next compliance period, e.g., for 2025, 2026, and 2027 by June 

1, 2024. Recording these allowance allocations in advance of the 

first year for which they could be used for compliance would 

facilitate compliance planning by owners and operators and 

promote robust allowance markets, including futures markets for 

allowances. 

The process for transferring allowances from one account to 

another would be quite simple. A transfer would be submitted 

providing, in a format prescribed by the Administrator, the 

account numbers of the accounts involved, the serial numbers of 

the allowances involved, and the name and signature of the 

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 
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Administrator would record the transfer by moving the allowances 

from the transferor account to the transferee account within 5 

business days of the receipt of the transfer form. 

5. Compliance with Emissions Limitations

Once the compliance period has ended (e.g., at midnight on 

December 31, 2024 for the first compliance period), facilities 

with affected EGUs would have a window of opportunity following 

the compliance period to evaluate their reported emissions and 

obtain any allowances that they might need to cover their 

emissions during the compliance period. For example, the 

allowance transfer deadline for the first compliance period

would be midnight on May 1, 2025 (the EPA is also requesting 

comment on earlier or later allowance transfer deadlines). Each 

allowance issued in the proposed mass-based trading program 

would authorize emission of one ton of CO2 and so would be usable 

for compliance, for the compliance period that includes the year 

for which the allowance was allocated or a later compliance

period. Consequently, each affected EGU would need, as of the 

allowance transfer deadline, to have in its facility compliance 

account, or to have a properly submitted transfer that would 

move into its compliance account, enough allowances usable for 

compliance to authorize its total emissions for the compliance

period. The authorized account representative could identify 

specific allowances to be deducted, but, in the absence of such 
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identification or in the case of a partial identification, the 

Administrator would deduct on a first-in, first-out basis.

Deducting allowances may have tax and accounting implications, 

so having a default deduction method provides the 

representatives with certainty regarding which allowances will 

be deducted for compliance. Allowances that are deducted for 

compliance will remain in the system in an EPA account, which 

ensures they will not be used again. If a facility were to 

fail to hold sufficient allowances for compliance by all 

affected EGUs at the facility, then the owners and operators of 

the facility and each affected EGU at the facility would have to 

provide, for deduction by the Administrator, two allowances 

allocated for the compliance period in the next year for every 

allowance that the owners and operators failed to hold as 

required to cover emissions. This submittal of two times the 

allowances required for the prior period is an ongoing 

obligation until compliance is achieved, and there is an ongoing 

obligation to comply in the current period. In addition, these

owners and operators would be subject to civil penalties for 

each violation in accordance with the CAA, 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 
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deduction of one allowance per allowance that the owners and 

operators failed to hold would offset this failure. The 

automatic deduction of another allowance per allowance that the 

owners and operators failed to hold that could not be avoided, 

regardless of any explanation provided by the owners and 

operators for their failure, would provide a strong incentive 

for compliance with the allowance-holding requirement by 

ensuring that non-compliance would be a significantly more 

expensive option than compliance. Such automatic deductions have 

been successfully used in prior programs including the CAIR, 

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 ARP

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 40 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 ARP

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 ARP are subject to the MATS program 

and, therefore, will have already installed stack flow rate 
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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 mercury 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 RGGI 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 
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2021 — compliance with the requirement to hold allowances would 

commence on the compliance period schedule that is detailed in 

section V.C of this preamble.

VI. Implementation of the Federal Plan and Delegation

Under section 111(d) of the CAA, the EPA adopts EGs that 

are then implemented when the EPA approves a state or tribal115

plan or promulgates a federal plan that implements and enforces 

the EGs for affected EGUS in states or areas of Indian country116

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 

 

115 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.

116 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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in the event that it becomes necessary for the EPA to directly 

regulate affected EGUS under CAA section 111(d), states and 

eligible tribes may still seek a delegation of authority from 

the EPA to implement a federal plan, similar to the ability to 

take delegated authority under other CAA programs. The EPA 

encourages states and eligible tribes that do not submit 

approvable plans to request delegation 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.117 118

 

117 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.

118 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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A. Delegation of the Federal Plan and Retained Authorities

If a state or tribe119 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 has been held on the state or tribal 

delegation request, and (4) include a memorandum of agreement 

between the state or tribe and the EPA that sets forth the terms 

and conditions of the delegation, the effective date of the 

agreement and the mechanism to transfer authority. Upon 

signature of the agreement, the appropriate EPA Regional Office 

 

119 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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would publish an approval notice in the Federal Register, 

thereby incorporating the delegation of authority into the 

appropriate subpart of 40 CFR part 62. See also EPA’s 

Delegations Manual, Delegation 7-139, “Implementation and 

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 may retain and not 

transfer authority to a state or tribe to approve certain items 

promulgated in the 2015 CAA section 111(d) Clean Power Plan.

This proposed federal plan also specifies that EGU owners 

or operators who wish to petition the agency for any alternative 

requirement should submit a request to the Regional 

Administrator with a copy set to the appropriate state.

B. Mechanisms for Transferring Authority
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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 

tribes to attempt to reconcile areas of the plan that are 

unapprovable. 
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Upon the effective date of an approved state or tribal 

plan, the federal plan would no longer apply to EGUs covered by 

such a plan and the state or local agency, or the tribe, would 

implement and enforce the state or tribal plan in lieu of the 

federal plan. The timing of effectiveness of an approved state 

or tribal plan in this circumstance may depend in part on the 

need to ensure a smooth transition and maintain regulatory 

certainty. Thus, for example, under a mass-based federal plan, 

we propose to handle these transitions so that they coincide 

with the compliance periods. The approval of a state or tribal 

plan would also involve a public comment process, which would

give interested stakeholders including any affected EGUs, the 

opportunity to comment. This will assist in ensuring that 

compliance, program integrity, electric reliability, and other 

critical factors are maintained. When an EPA Regional Office 

approves a state or tribal plan, it will amend the appropriate 

subpart of 40 CFR part 62 or 40 CFR part 49, respectively, to 

indicate such approval, as well as the timing of its 

effectiveness.

As discussed elsewhere in this document, the EPA may also 

in certain circumstances approve a partial state or tribal plan 

(sometimes called an “abbreviated state plan”) that may modify 

certain limited provisions in the federal plan trading program. 

For example, this could occur if a state or tribe wishes to 
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handle the initial allocation of allowances in a mass-based 

trading program, as discussed in section 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 EGs would 

generally apply to a partial state or tribal plan, just as they 

would a full state or tribal plan. The scope of the requirement, 

however, would be commensurate with the scope of the partial 

plan. For instance, if a state or tribe seeks approval of a 

partial plan solely to handle allowance allocations, then the 

required statement of legal authority would be limited to those 

legal authorities the state or tribe must have to implement and 

enforce this component of the trading program.

2. State or Tribe Takes Delegation of the Federal Flan

The EPA, in its discretion, may delegate to state or tribal 

air agencies the authority to implement this federal plan. As 

discussed above, the EPA believes that it is advantageous and 

the best use of resources for state or local agencies or tribes 

to agree to undertake, on the EPA’s behalf, administrative and 

substantive roles in implementing the federal plan to the extent 

appropriate and where authorized by state or tribal law. If a 
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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.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 

be the primary office within the agency with delegated CAA 

section 111(d)(2) authority. See Delegation 7-139, section 3(c). 
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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 EGs. Section 301(d) of the CAA and 40 CFR 

part 49 authorize the Administrator to treat an Indian Tribe in 

the same manner as a state (TAS) for purposes of developing and 

implementing a tribal plan implementing the EG. See 40 CFR 49.3; 

see also “Indian Tribes: Air Quality Planning and Management,”

hereafter “Tribal Authority Rule,” (63 FR 7254, February 12, 

1998). We invite tribes with EGU in their area of Indian country 

to comment on the level of their interest, if any, in developing 

their own plans. 

The EPA is proposing in this action to find that it is 

necessary or appropriate to regulate affected EGUs in each of 

the three areas of Indian country that have affected EGUs under 

the proposed federal plan. The EPA is authorized to directly 

implement the EGs in Indian country when it finds, consistent 

with the authority of CAA section 301 which the EPA has 

exercised in 40 CFR 49.11, that it is necessary or appropriate 

to do so. In the final EGs, the EPA establishes emission 

performance rates for the four EGUs located in Indian country 

and mass and rate-based emission goals for each of the three 

affected areas of Indian country. These areas include lands of 

the Navajo Nation’s reservation, lands of the Ute Tribe of the 
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Uintah and Ouray Reservation, and lands of the Fort Mojave 

Tribe’s reservation. The EPA proposed carbon pollution EGs for 

EGUs in these areas and U.S. Territories in a Supplemental 

Notice of Proposed Rulemaking. See 79 FR 65482 (Nov. 4, 2014). 

The four facilities with affected EGUs located in Indian country 

that the EPA identified in the Supplemental Notice are: the 

South Point Energy Center, on the Fort Mojave Reservation 

geographically located within Arizona; the Navajo Generating 

Station, on the Navajo Indian Reservation geographically located 

within Arizona; the Four Corners Power Plant, on the Navajo 

Indian Reservation geographically located within New Mexico; and 

the Bonanza Power Plant, on the Uintah and Ouray Indian 

Reservation geographically 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. 

In this action, we are proposing to find that it is 

necessary or appropriate, in each of the three areas of Indian 

country that have affected EGUs, to establish a federal plan 

that applies to the four power plants located on the Navajo 

Nation, the Fort Mojave Indian Reservation, and the Uintah and 

Ouray Reservation of the Ute Tribe. The affected EGUs located on 

the Navajo Nation are in an area of Indian country located 

within the continental U.S., are interconnected with the western 
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electricity grid, and are owned and operated by entities that 

generate and provide electricity to customers in several states. 

The affected EGU located on the Uintah and Ouray Reservation of 

the Ute Tribe is in an area of Indian country located within the 

continental 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 have expressed a clear intent to develop and 

seek approval of a tribal implementation plan. Thus, absent a 

federal plan, the significant emissions from these four power 

plants could go unregulated by the Clean Power Plan.

Because the agency has finalized emission performance 

targets for these power plants in the EGs, there is, in our 

view, little benefit to be had by not proposing to include them 

in a federal plan now and a potentially significant downside to 

not doing so; the reductions the EPA has determined are 

achievable in the EGs would become more difficult and costly for 

these power plants to achieve if they are delayed in entering 
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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 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 
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to administer aspects of any applicable federal plan that is 

ultimately promulgated. In the event a federal plan is needed, 

proposing a necessary or appropriate finding at this time will 

allow the EPA to expeditiously promulgate a final federal plan 

for one or all of these power plants in the future to allow 

trading to occur. We will continue to consult with the 

governments of the Navajo Nation, Fort Mojave Indian Tribe, and 

the Ute Tribe of the Uintah and Ouray Reservation during the 

comment period for this proposal, and prior to taking any action 

to finalize a necessary or appropriate finding and/or a federal 

plan. Comments on the appropriateness of the proposed finding, 

should be submitted within the comment period specified in the 

Dates section of this preamble.

VII. Amendments to Process for Submittal and Approval of State 

Plans and EPA Actions 

As indicated in the final rulemaking notice for the CAA 

section 111(d) guideline, “Carbon Pollution Emission Guidelines 

for Existing Stationary Sources: Electric Utility Generating 

Units,” in this action, in addition to the proposed federal 

plans and model trading rules, the EPA is also proposing to 

amend the framework regulations and update the process for 

acting on CAA section 111(d) state plans under 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 
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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 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 
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require the CAA section 111(d) procedures to be identical to 

those the EPA uses under CAA section 110 for SIPs.120 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.

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 CAA 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 

 

120 See Webster’s II New Riverside University Dictionary (Riverside 1988) 

(defining “similar” to mean “resembling though not completely identical”).
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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 CAA

Amendments. The EPA is proposing to amend the procedures for 

approval or disapproval of CAA section 111(d) state plans to 

reflect the enhancements Congress included in CAA section 110 

for agency actions on SIPs. These proposed amendments are 

discussed in more detail below.

A. Partial Approvals/Disapprovals

First, the EPA proposes to add authority similar to that 

under CAA section 110(k)(3) to partially approve or disapprove a 

plan.121 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 

 

121 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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must disapprove the full plan, but rather to allow the state to 

move forward with those portions of the plan that are 

approvable. This mechanism are those situations where the state 

wishes to take over a discrete part of a federal plan. For 

instance, in this proposal, states will be able to seek approval 

of a partial state plan that will give them the ability to 

handle the allocation of allowances under a mass-based federal 

plan.

In cases where elements of a plan are functionally 

severable from each other, and one element is approvable while 

another is not, this provision will authorize the EPA to approve 

one part of a plan and disapprove the other. It will also 

authorize the EPA to accept and review a state plan that is only 

partial in nature, if identified by the state as such, so long 

as the other applicable submission requirements are met (such as 

demonstration of legal authority and completion of the public 

process). When the state submits what it intends to be a full 

state plan (rather than just a partial plan), the EPA proposes 

that the approvable portion of a plan must be functionally 

severable from the rest of the plan, and this will be the case

when the following conditions are met. First, the approvable 

portion of the plan must not depend on the rest of the plan. In 

other words, the disapproval of the remaining portion of the 

plan must not affect the portion that is approved. Second, 
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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) 

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 1 year from the effective date of the 

conditional approval. If the state fails to meet its commitment, 

the conditional approval is treated as a disapproval. 
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Incorporating this mechanism under the framework regulations for 

CAA section 111(d) will enable the EPA to approve a state to 

begin to administer a substantially complete program that 

requires only specific changes to be fully approvable. 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 SIP 

does not comply with the requirements of the CAA. To date, the 

EPA has not considered using a similar procedure pursuant to the 

authority under CAA section 111(d). We now propose to do so. The 

ability to call for plan revisions is fundamental to a program 

that will be implemented over many years multiple decadUnder the 

Clean Power Plan EGs, states have more than a decade to fully 

implement emissions standards or state measures in order to 

ensure affected EGUs achieve the emission goals of the EGs. 

Throughout 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 
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by the EGs. In that case, having a procedural mechanism 

available under CAA section 111(d) similar to the so-called “SIP 

call” mechanism in CAA section 110(k)(5) will allow the agency 

to initiate a process with the state to make necessary revisions 

to ensure the plan functions properly. 

Accordingly, the EPA is proposing to amend the framework 

regulations to include a provision similar to CAA section 

110(k)(5) under which the EPA may find that a state’s CAA 

section 111(d) plan is substantially inadequate to comply with 

the requirements of the CAA and require the state to revise the 

plan as necessary to correct such inadequacies. Consistent with

CAA section 110(k)(5), the EPA shall notify the state of any 

inadequacies and establish a reasonable deadline for the state 

to submit required plan revisions. That deadline will not exceed 

18 months after the date of the notice. The EPA will make its 

finding and notice to the state available to the public.122

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 

 

122 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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inadequacy establishes a plan submittal deadline subject to the 

provisions of CAA section 111(d)(2)(A). A finding of failure to 

meet that new deadline triggers the EPA’s authority to issue a 

federal plan for the state. The EPA may promulgate a federal 

plan at any time following the state’s failure to timely submit 

an adequate plan that addresses the EPA’s finding. 

While these authorities are important, the intention of 

having a mechanism to call for plan revisions is to have a way 

to initiate an orderly process to improve plans when they are 

not meeting program objectives. It is the EPA’s hope that a call 

for plan revision leads to a constructive dialogue with a state 

or states, and ultimately, an improved and more effective CAA 

section 111(d) plan.

The EPA is also proposing that the agency can call for a 

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 
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mechanisms available in the SIP program to provide a similar 

process that assures effective state plan implementation under 

CAA section 111(d). Under CAA section 110(k)(5), the EPA may 

call for a revision of a state plan “[w]henever the 

Administrator finds that the . . . plan . . . is substantially 

inadequate to . . . comply with any requirement of [the Act].”

If the state does not submit a plan revision in response to the 

call to cure the failure to provide for implementation, the EPA 

would have the authority to promulgate the federal plan being 

proposed. 

One critical requirement of CAA section 111(d)(1)(B) is 

that a state must submit a plan that “provides for the 

implementation and enforcement of such standards of performance” 

(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 
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attain or maintain the relevant national ambient air quality 

standard.” In the context of CAA section 111, this authority 

translates into the EPA calling a state plan when the agency 

finds that it is substantially inadequate to achieve the 

emissions reductions required under the EG. If a state has 

failed to implement its plan, and that failure is pervasive 

enough to render the requirements of the plan ineffective, it is 

reasonable for the EPA to find that the state plan is 

substantially inadequate to achieve the emissions reductions 

required under the EG. The state’s failure to implement has 

revised the effect of the plan so that it is no longer adequate 

to meet the 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 
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to provide notice and a public hearing on each new SIP 

submittal. Incorporating this mechanism into the CAA section

111(d) framework regulations will allow the EPA to fix errors in 

its prior actions on state plans without imposing on the states 

the corresponding burden of providing notice and a public 

hearing as required under the CAA section 111(d) framework 

regulations. 40 CFR 60.23.

D. Completeness Criteria

Completeness criteria provide the agency with a means to 

determine whether a submission by a state includes the minimum 

elements that must be met before the EPA is required to act on 

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 
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Appendix V for determining the completeness of submissions under 

CAA section 111(d). The completeness criteria can be grouped 

into: (1) Administrative materials; and (2) technical support. 

The EPA proposes that both groups would apply to all CAA section 

111(d) rules going forward. The agency notes that the addition 

of completeness criteria in the framework regulations does not 

alter any of the submission requirements states already have 

under the EGs. 

For administrative materials, the EPA is proposing 

completeness criteria that mirror the existing administrative 

criteria for SIP submittals because the two programs have 

similar administrative processes. The EPA proposes that a 

complete final state plan submittal under CAA section 111(d)

must include: (1) A formal letter of submittal from the Governor 

or her designee requesting EPA approval of the plan or revision 

thereof; (2) evidence that the state has adopted the plan in the 

state code or body of regulations (That evidence shall include 

the date of adoption or final issuance as well as the effective 

date of the plan, if different from the adoption/issuance 

date.); (3) Evidence that the state has the necessary legal 

authority under state law to adopt and implement the plan; and 

(4) a copy of the actual regulation, or document submitted for 

approval and incorporation by reference into the plan. The 

submittal shall be a copy of the official state 
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regulation/document signed, stamped and dated by the appropriate 

state official indicating that it is fully enforceable by the 

state. The effective date of the regulation/document shall, 

whenever possible, be indicated in the document itself. The 

state’s electronic copy must be an exact duplicate of the hard 

copy. For revisions to the approved plan, the submittal shall 

indicate the changes made (for example, by 

redline/strikethrough) to the approved plan; (5) evidence that 

the state followed all of the procedural requirements of the 

state's laws and constitution in conducting and completing the 

adoption/issuance of the plan; (6) evidence that public notice 

was given of the proposed change with procedures consistent with 

the requirements of 40 CFR 60.23, including the date of 

publication of such notice; (7) certification that public 

hearing(s) were held in accordance with the information provided 

in the public notice and the state's laws and constitution, if 

applicable and consistent with the public hearing requirements 

in 40 CFR 60.23; and (8) compilation of public comments and the 

state's response thereto.

These criteria, as proposed, are intended to be generic to 

all CAA section 111(d) plans going forward, with the proviso 

that specific EGs may provide otherwise. The technical support 

completeness criteria that the EPA proposes will also be generic 

to all CAA section 111(d) rules, with the same proviso. The EPA 
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proposes that the technical support required for all plans must 

include each of the following: (1) Description of the plan 

approach and geographic scope;(2) identification of each 

designated facility, identification of emission standards for 

the designated facilties, and monitoring, recordkeeping, and 

reporting requirements that will determine compliance by each 

designated facility; (3)identification of compliance schedules 

and/or increments of progress; (4) demonstration that the state 

plan submittal is projected to achieve emissions performance 

under the applicable EGs; (5) documentation of state 

recordkeeping and reporting requirements to determine the 

performance of the plan as a whole; and (6) demonstration that 

each emission standard is quantifiable, non-duplicative, 

permanent, verifiable, and enforceable.

The EPA proposes a process similar, though not identical, 

to that set forth in 40 CFR 51.103 and Appendix V to 40 CFR part 

51 to make completeness determinations. Similar to CAA section 

110(k)(1)(C), under this proposal, where the EPA determines that 

a state submission required under CAA section 111(d) does not 

meet the minimum completeness criteria we are proposing to 

establish, the state will be considered to have not made the 

submission. The EPA further proposes that, similar to CAA 

section 110(k)(1)(B), within 60 days of the EPA's receipt of a 

state submission, but no later than 6 months after the date, if 
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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 

complete is not a finding that the submittal meets the 

substantive requirements of CAA section 111(d) or the guideline. 

That must be done via the process for approval or disapproval of 

a state plan, which would be done through notice and comment 

rulemaking. In the completeness process, the EPA will confirm 

that a state’s submittal appears to have addressed the criteria 

for a complete submittal and, therefore, the submittal is 

sufficient to trigger the EPA’s obligation to act on it. But in 

the completeness process the agency will not assess the content

of those submissions to determine if they are approvable. 

Accordingly, even when the EPA affirmatively determines that a 

submittal is complete, it does not prevent the agency from later 

finding that the state plan does not meet the requirements of 

the EGs, including finding that the submittal failed to address 

a required element and must be disapproved.
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Similarly, when a submittal is determined to be complete by 

operation of law after 6 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 EPA begins 

review of the state plan that is complete by operation of law, 

the agency must go through the process of disapproving (or 

partially disapproving or conditionally approving, as discussed 

below) that plan, unless the state and the EPA work together to 

cure the deficiency. In other words, the EPA cannot simply find 

the plan incomplete and return it to the state at that point. 

But the finding of completeness by operation of law in no way 

prevents the EPA from subsequently concluding that the state’s 

submission is missing a required element of the program and 

making that finding as part of a disapproval of the plan.

As described in the final rulemaking notice for the CAA 

section 111(d) EGs, a state will submit all CAA section 111(d) 

plans electronically. If the EPA determines that any submission 

fails to meet the completeness criteria, the agency may return 

the plan to the state and request corrections, identifying the 
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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 

state and the EPA are “parallel processing” the final plan. 

Parallel processing allows a state to submit the plan prior to 

final adoption by the state and provides an opportunity for the 

state to consider the EPA’s comments prior to submission of a 

final plan for final review and action. The EPA would propose to 

take action on a state plan based on a proposed state 

regulation. The EPA would only finalize the action if the state 

adopts a final plan that is legally effective under state law. 

The EPA would only approve the plan if the state addressed any 

corrections that the EPA identified in its proposed action on 

the state plan without any other material change to the plan. 

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.

E. Update to Deadlines for EPA Actions
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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 CO2 EG for EGUs have already adjusted the deadline 

in 60.27(b) to require the EPA to act on a state plan under 

those EGs within 12 months (rather than 4 months) after the date 

required for submission of a plan. See 40 CFR 60.5715. However, 

the Clean Power Plan EGs did not modify the 6 month deadline for 

a federal plan in 60.27(d).

The EPA is proposing to amend 40 CFR 60.27(b) to allow the 

EPA 12 months to approve or disapprove submittals of all plans 

or plan revisions under CAA section 111(d), not just those 

related to the Clean Power Plan under 60.5715. This change would 
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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 6 month deadline for issuing a final federal plan in 

60.27(d) to 1 year123; 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 

 

123 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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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 6 months of the deadline for state 

submittals, may be outdated and unrealistic with respect to the 

timelines for review of state plans and the time periods for 

action, particularly as informed by the agency's experience with 

CAA section 110 SIPs (which led to the extension of the 

timelines and other changes to CAA section 110 in the 1990 

Amendments discussed above). Third, in the CPP Emission 

Guideline, the EPA has finalized a timing requirement that gives 

the agency a year to approve or disapprove a state plan or 

revision. The existing requirement in 60.27(d) that the EPA must 
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promulgate a federal plan within 6 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 CAA, 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. 

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, 
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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. 

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 
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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 

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, 
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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 

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.
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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 considered the effects 

of this proposed rule and has reviewed applicable ESA 

regulations, case law, and guidance to determine what, if any, 

impact there may be to listed endangered or threatened species 

or designated critical habitat. Section 7(a)(2) of the ESA 

requires federal agencies, in consultation with the U.S. Fish 

and Wildlife Service (FWS) and/or the National Marine Fisheries 

Service, to ensure that actions they authorize, fund, or carry 

out are not likely to jeopardize the continued existence of 

federally listed endangered or threatened species or result in 

the destruction or adverse modification of designated critical 

habitat of such species. 16 U.S.C. 1536(a)(2). Under relevant 

implementing regulations, ESA section 7(a)(2) applies only to 

actions where there is discretionary federal involvement or 

control. 50 CFR 402.03. Further, under the regulations 

consultation is required only for actions that “may affect” 

listed species or designated critical habitat. 50 CFR 402.14. 

Consultation is not required where the action has no effect on 

such species or habitat. Under this standard, it is the federal 

agency taking the action that evaluates the action and 

determines whether consultation is required. See 51 FR 19926, 
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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.124 Indirect effects are those that are caused by the 

action, later in time, and are reasonably certain to occur. Id.

To trigger a consultation requirement, there must thus be a 

causal connection between the federal action, the effect in 

question, and if the effect is indirect, it must be reasonably 

certain to occur.

The EPA has considered the effects of this proposed rule 

and has reviewed applicable ESA regulations, case law, and 

guidance to determine what, if any, impact there may be to 

listed species or designated critical habitat for purposes of 

ESA section 7(a)(2) consultation. The EPA notes that the 

projected environmental effects of this proposal are, like the 

EGs that it implements, positive: reductions in overall GHG 

emissions, and reductions in PM and ozone-precursor emissions 

(SOX and NOX), for EGUS that will be covered by the federal plan. 

However, the EPA’s assessment that the rule will have an overall 

 

124 See Endangered Species Consultation Handbook, U.S. Fish & Wildlife Service 

and National Marine Fisheries Service at 4-25(March 1998) (providing examples 

of direct effects: e.g., driving an off road vehicle through the nesting 

habitat of a listed species of bird and destroying a ground nest; building a 

housing unit and destroying the habitat of a listed species).
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net positive environmental effect by virtue of reducing 

emissions of certain air pollutants does not address whether the 

rule may affect any listed species or designated critical 

habitat for ESA section 7(a)(2) purposes and does not constitute 

any finding of effects for that purpose. The fact that the rule 

will have overall positive effects on the national and global 

environment does not mean that the rule may affect any listed 

species in its habitat or the designated critical habitat of 

such species within the meaning of ESA section 7(a)(2) or the 

implementing regulations or require ESA consultation. The EPA 

has considered various types of potential effects in considering 

whether ESA consultation is required for this rule.

With respect to the projected GHG emission reductions, the 

EPA does not believe that such reductions trigger ESA 

consultation requirements under ESA section 7(a)(2). In reaching 

this conclusion, the EPA is mindful of significant legal and 

technical analysis undertaken by FWS and the U.S. Department of 

the Interior in the context of listing the polar bear as a 

threatened species under the ESA. In that context, in 2008, FWS 

and DOI expressed the view that the best scientific data 

available were insufficient to draw a causal connection between 
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GHG emissions and effects on the species in its habitat.125 The 

DOI Solicitor concluded that where the effect at issue is 

climate change, proposed actions involving GHG emissions cannot 

pass the “may affect” test of the ESA section 7 regulations and,

thus, are not subject to ESA consultation. 

The EPA has also previously considered issues relating to 

GHG emissions in connection with the requirements of ESA section 

7(a)(2). In the final EGs, the agency noted that, although the 

GHG emission reductions projected for the EGs are large 

(estimated reductions of about 415 million short tons of CO2 in 

2030 relative to the base case), the EPA evaluated larger 

reductions in assessing this same issue in the context of the 

light duty vehicle GHG emission standards for model years 2012-

2016 and 2017-2025. There the agency projected emission 

reductions over the lifetimes of the model years in question,126

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. 

 

125 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).

126 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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Extrapolating from global metric to local effect with such small 

numbers, and accounting for further links in a causative chain,

remain beyond current modeling capabilities.” EPA, Light Duty 

Vehicle Greenhouse Gas Standards and Corporate Average Fuel 

Economy Standards, Response to Comment Document for Joint 

Rulemaking at 4-102 (Docket EPA-OAR-HQ-2009-4782). The EPA 

reached this conclusion after evaluating issues relating to 

potential improvements from the fuel efficiency rule relevant to 

both temperature and oceanographic pH outputs. The EPA's 

ultimate finding was that “any potential for a specific impact 

[of the specific federal action] on listed species in their 

habitats associated with these very small changes in average 

global temperature and ocean pH is too remote to trigger the 

threshold for ESA section 7(a)(2).” Id. 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). The EPA similarly proposes to 

determine that the likelihood of jeopardy to a species from 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 SO2 and NOx as a collateral 

consequence of this proposal (which will be, as stated above, 
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only a subset of the total reductions from the EGs). However, 

CAA section 111(d) cannot directly control emissions of criteria 

pollutants. And furthermore, a federal plan under CAA section 

111(d)(2) does no more than prescribe emissions standards of the 

same stringency as the corresponding EGs. 40 CFR 60.27(e)(1). 

Consequently, CAA section 111(d) provides no discretion to set a 

standard in a federal plan based on potential impacts to 

endangered species of reduced criteria pollutant emissions. ESA 

section 7(a)(2) consultation is not required with respect to the 

projected reductions of criteria pollutant emissions. See 50 CFR 

402.03; see also WildEarth Guardians v. U.S. Envt’l Protection 

Agency, 759 F.3d 1196, 1207-10 (10th Cir. 2014) (the EPA has no 

duty to consult under section 7 of the ESA regarding HAP

controls that it did not require -- and likely lacked authority 

to require -- in a FIP for regional haze controls under section 

169A of the CAA.).

Finally, the EPA has also considered other potential 

effects of the rule (beyond reductions in air pollutants) and 

whether any 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 
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received comments on the EGs asserting that because potential 

increased reliance on wind or solar power may be an element of 

Building Block 3, and because wind and solar facilities may in 

some cases have effects on listed species, the EPA must consult 

under the ESA on this aspect of the rule. 

The EPA has carefully considered the comments and the 

correspondence from Congress as well as the case law and other 

materials cited in those documents. The EPA does not believe 

that the effects of potential future changes in the energy 

sector – including increased reliance on wind or solar power as 

a result of future potential actions by states or other 

implementing entities – or any potential alterations in the 

operations of any particular facility would, at the time of 

promulgation of a federal plan, be sufficiently certain to occur 

so as to require ESA consultation on the rule. The EPA 

appreciates that the ESA regulations call for consultation where 

actions authorized, funded, or carried out by federal agencies 

may have indirect effects on listed species or designated 

critical habitat. However, as noted above, indirect 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 
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designated habitat are too uncertain to require consultation 

under ESA section 7. This is so for at least two reasons: (1)

The EPA cannot know with any certainty at this stage which 

states will actually become subject to a finally promulgated 

federal plan. Which affected EGUs, in which states, will be 

covered by this Plan can only be known after states have failed 

to submit a plan, or have had their plans disapproved by the 

EPA; and (2), the federal plan as proposed will be implemented 

through some form of emissions trading. Emissions trading 

inherently provides maximum flexibility to individual affected 

EGUs to choose their method of compliance, including continuing 

to emit the relevant pollutant at historical rates so long as 

the affected EGU holds sufficient credits or allowances. At this 

point, the EPA has no meaningful information to express in any 

more than the broadest terms how any particular affected EGU may 

choose to comply with the federal plan, should it be promulgated 

for them based on their location in an area not covered by an 

approved state plan. The Services have explained that ESA

section 7(a)(2) was not intended to preclude federal actions 

based on potential future speculative effects.127 These are 

 

127 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 
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precisely the types of speculative future activities and effects 

currently at issue here. The EPA requests comment on its 

proposed conclusion that ESA section 7 consultation is not 

required for this action. The EPA will continue to evaluate the 

scope and potential effects of federal planning activities for 

this source category to the extent federal plans are needed and 

implemented in specific areas and over specific sources.

B. What are the Air Impacts? 

The EPA anticipates significant emission reductions under 

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 

 

& 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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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.128

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 

 

128 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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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

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
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2030

Base Case 2,227 1,314 1,293

Mass-based Federal Plan Approach 1,814 1,034 1,015

Emissions Reductions 413 280 278

Source: Integrated Planning Model, 2015. 

Note: Emissions may not sum due to rounding. 

The reductions in Tables 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? 

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%
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Coal production for power 

sector use -5% -14% -25% -7% -17% -24%

Price of natural gas 

delivered to power sector 5% -8% 2% 4% -3% -2%

Natural gas use for 

electricity generation 3% -1% -1% 5% 0% -4%

These figures reflect the EPA’s modeling that presumes 

policies that lead to generation shifts and growing use of DS-EE

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?

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. 
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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 

estimates are available in the RIA included in the rulemaking 

docket. 

E. What are the Economic and Employment Impacts?

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 
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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.

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 
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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 

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 
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elsewhere. This analysis also does not capture potential 

economy-wide impacts due to changes in prices (of fuel, 

electricity, labor, for example) or other factors such as 

improved labor productivity and reduced health care expenditures 

resulting from cleaner air. For these 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 
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$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 

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 
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carbon (SC-CO2) estimates for the analysis years and are rounded to two 

significant figures. 

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
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SO2 318 $12 to $28 $11 to $25

NOX 282 $1.0 to $2.3 $0.93 to $2.1

Ozone precursor c

NOX (ozone season only) 118 $0.86 to 

$3.7 $0.86 to $3.7

Total Monetized Health Co-benefits $14 to $34 $13 to $31

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$34 to $54 $33 to $51

a All estimates are rounded to two significant figures, so estimates may not 

sum. It is important to note that the 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.
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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)

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
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Ozone precursor c

NOX (ozone season only) 121 $0.82 to $3.5 $0.82 to $3.5

Total Monetized Health Co-benefits $12 to $28 $11 to $26

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$32 to $48 $31 to $46

a All estimates are rounded to two significant figures, so estimates may not 

sum. It is important to note that the monetized co-benefits do not include 

reduced health effects from direct exposure to SO2, direct exposure to NO2, 

exposure to mercury, ecosystem effects or visibility impairment. Air 

pollution health co-benefits are estimated using regional benefit-per-ton 

estimates for the contiguous U.S.

b The monetized PM2.5 co-benefits reflect the human health benefits associated 

with reducing exposure to PM2.5 through reductions of PM2.5 precursors, such as 

SO2 and NOX. The 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 
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rulemaking.129 We refer to these estimates, which were developed 

by the U.S. government, as “SC-CO2 estimates.” The SC-CO2 is a 

metric that estimates the monetary value of impacts associated 

with marginal changes in CO2 emissions in a given year. It 

includes a wide range of anticipated climate impacts, such as 

net changes in agricultural productivity and human health, 

property damage from increased flood risk, and changes in energy 

system costs, such as reduced costs for heating and increased 

costs for air conditioning. It is typically used to assess the 

avoided damages as a result of regulatory actions (i.e., 

benefits of rulemakings that lead to an incremental reduction in 

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 

 

129 Docket ID EPA-HQ-OAR-2013-0495, Technical Support Document: Technical 

Update of the Social Cost of Carbon for Regulatory Impact Analysis Under 

Executive Order 12866, Interagency Working Group on Social Cost of Carbon, 

with participation by Council of Economic Advisers, Council on Environmental 

Quality, Department of Agriculture, Department of Commerce, Department of 

Energy, Department of Transportation, Domestic Policy Council, Environmental 

Protection Agency, National Economic Council, Office of Management and 

Budget, Office of Science and Technology Policy, and Department of Treasury 

(May 2013, Revised July 2015). Available at: 

http://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-tsd-final-july2015.pdf.
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(IAMs) to develop the SC-CO2 estimates and recommended four 

global values for use in regulatory analyses. The SC-CO2

estimates were first released in February 2010 and updated in 

2013 using new versions of each IAM. The 2010 SC-CO2 Technical 

Support Document (2010 TSD)130 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).131

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 

 

130 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.

131 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).
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continues to recommend the use of the SC-CO2 estimates in RIA.132

With the release of the response to comments, the IWG announced 

plans to obtain expert independent advice from the National 

Academies of Sciences, Engineering, and Medicine (Academies) to 

ensure that the SC-CO2 estimates continue to reflect the best 

available scientific and economic information on climate change. 

The Academies review will be informed by the public comments 

received and focus on the technical merits and challenges of 

potential approaches to improving the SC-CO2 estimates in future 

updates. See the EPA Response to Comments document for the 

complete response to comments received on SC-CO2 as part of this 

rulemaking. 

Concurrent with OMB’s publication of the response to 

comments on SC-CO2 and announcement of the Academies process, OMB 

posted a revised TSD that includes two minor technical 

corrections to the current estimates. One technical correction 

addressed an inadvertent omission of climate change damages in 

the last year of analysis (2300) in one model and the second 

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 

 

132 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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May 2013 TSD. The change in the estimates associated with the 

95th percentile estimates when using a 3 percent discount rate 

is slightly larger, as those estimates are heavily influenced by 

the results from the model that was affected by the indexing 

error. 

The EPA, as a member of the IWG on the SC-CO2, has carefully 

examined and evaluated the minor technical corrections in the 

revised TSD and the public comments submitted to OMB’s 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 

$120 per short ton of CO2 emissions in the year 2020 (2011$).133

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 

 

133 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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intergenerational context (where costs and benefits are incurred 

by different generations). The fourth value is the 95th

percentile of the SC-CO2 from all three models at a 3 percent 

discount rate. It is included to represent higher-than-expected 

impacts from temperature change further out in the tails of the 

SC-CO2 distribution (representing less likely, but potentially 

catastrophic, outcomes).

There are limitations in the estimates of the benefits from 

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 
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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 

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 BenMAP134 to calculate average regional benefit-per-ton 

estimates using the health impact assumptions used in the PM 

 

134 http://www.epa.gov/airquality/benmap/index.html.
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NAAQS RIA135 and Ozone NAAQS RIAs.136,137 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.138 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 

 

135 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.

136 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>.

137 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. 

138 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)139 and 

Lepeule et al. (2012)140. 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, 

 

139 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.

140 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)141 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)142 and the upper end based on a 

benefit-per-ton estimate using the function from Levy et al. 

 

141 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.

142 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).143 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,144 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. 

 

143 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.

144 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,145 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. 

 

145 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 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 

EJ 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 GHGs, the most significant driver of climate change. 

While addressing climate change will provide broad benefits, it 
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is particularly beneficial to low-income populations and some 

communities of color (in particular, populations defined jointly 

by ethnic/racial characteristics and geographic location) where 

people are most vulnerable to the impacts of climate change (a 

more robust discussion of the impacts of climate change on 

vulnerable communities is provided in the Executive Order 12898 

section X.J of this preamble). While climate change is a global 

phenomenon, the adverse effects of climate change can be very 

localized, as impacts such as storms, flooding, droughts, and 

the like are experienced in individual communities. 

Vulnerable communities also often receive more than their 

fair share of conventional air pollution, with the attendant 

adverse health impacts.

The changes in electricity generation that will result from

this rule will further benefit communities by reducing existing 

air pollution that directly contributes to adverse localized 

health effects. These air quality improvements will be achieved 

through this rule because the EGUs that emit the most GHGs also 

have the highest emissions of conventional pollutants, such as 

SO2, NOx, fine particles, and HAP. These pollutants are known to 

contribute to adverse health outcomes, including the development 

of heart or lung diseases, such as asthma and bronchitis,

increased susceptibility to respiratory and cardiac symptoms, 

greater numbers of emergency room visits and hospital 
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admissions, and premature deaths.146 The EPA expects that the 

reductions in utilization of higher-emitting units likely to 

occur during the implementation of federal plans will produce 

significant reductions in emissions of conventional pollutants, 

particularly in those communities already overburdened by 

pollution, which are often low-income communities, communities 

of color, and indigenous communities. These reductions will have 

beneficial effects on air quality and public health both locally 

and regionally. Further, this rulemaking complements other 

actions 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 

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.

 

146 Six Common Air Pollutants. http://www.epa.gov/oaqps001/urbanair/
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There are other ways in which the actions that result from 

this rulemaking may affect overburdened communities in positive 

or potentially adverse ways and we also heard about these from 

commenters.

While the agency expects overall emission decreases as a 

result of this rulemaking, we recognize that some EGUs may 

operate more frequently. To the extent that we project increases 

in utilization as a result of this rulemaking, we expect these 

increases to occur generally in lower-emitting NGCC units, which 

have minimal or no emissions of SO2 and HAP, lower emissions of 

particulate matter, and much lower emissions of NOx compared to 

higher-emitting steam units. We acknowledge the concerns that 

have been raised on this point, but also the difficulty in 

anticipating prior to plan implementation where those impacts 

might occur. As described below, the EPA intends to conduct an 

assessment of whether and where emission increases may result 

from plan implementation and mitigate adverse impacts, if any, 

in overburdened communities.

In addition to the many positive anticipated health 

benefits of this rulemaking, it also will increase the use of 

clean energy and will encourage 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, 
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and will continue to be, investing more in RE and EE. The 

construction of renewable generation and the implementation of 

EE programs such as residential weatherization will bring 

investment and employment opportunities to the communities where 

they take place. It is important to ensure that all communities 

share in these benefits. And while we estimate that the benefits 

of this program will greatly exceed its costs (as noted in the 

RIA for this rulemaking), it is also important to ensure that to 

the extent there are increases in electricity costs, that those 

do not fall disproportionately on those least able to afford 

them. 

The EPA has engaged with community groups throughout this 

rulemaking and we received many comments on the issues outlined 

above from community groups, EJ organizations, faith-based 

organizations, public health organizations, and others. This 

input has informed this final rulemaking and prompted the EPA to 

consider other steps that the agency can take in the short and 

long term to assist states and stakeholders to consider EJ and 

impacts to communities in plan development and implementation. 

It has also prompted us to work with our federal partners 

to make sure that communities have information on federal 

resources available to assist them. We describe these resources 

below, as well as resources that the EPA will be providing to 
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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 

fundamental to beginning that process, the EPA has conducted a

proximity analysis for this proposed rulemaking that summarizes 

demographic data on the communities located near power plants.147

The EPA understands that, in order to prevent disproportionately 

high and adverse human health or environmental effects on these 

communities, both the agency and communities must have 

information on the communities living near facilities, including 

demographic data, and that accessing and using census data files 

requires expertise that some community groups may lack. 

Therefore, the EPA used census data from the American Community 

Survey (ACS) 2008-2012 to conduct a proximity analysis that can 

 

147 The proximity analysis was conducted using the EPA’s environmental justice 

mapping and screening tool, EJSCREEN.
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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 U.S. Included in the analysis 

is the breakdown by percentage of community characteristics such 

as income and minority status. The analysis shows a higher 

percentage of communities of color and low-income communities 

living near power plants than national averages. It is important 

to note that the impacts of power plant emissions are not 

limited to a 3-mile radius and the impacts of both potential 

increases and decreases in power plant emissions can be felt 

many miles away. Still, being aware of the characteristics of 

communities closest to power plants is a starting point in 

understanding how changes in the plant’s air emissions may 

affect the air quality experienced by some of those already 

experiencing environmental burdens. 

Although overall there is a higher fraction of communities 

of color and low-income populations living near power plants 

than national averages, there are differences between rural and 

urban power plants. There are many rural power plants that are 
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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 EJ considerations, we use 

the terms “vulnerable” or “overburdened” when referring to these 

communities. Our intent is for these terms to be understood in 

an expansive sense, in order to capture the full scope of 

communities, including indigenous communities most often located 

in rural areas, that are central to our EJ and community 

considerations.

As stated in the Executive Order 12898 discussion located 

in section X.J of this preamble, the EPA believes that all 

communities will benefit from this proposed rulemaking because 

this action directly addresses the impacts of climate change by 

limiting GHG emissions through the establishment of CO2 emission 

standards for existing affected fossil fuel-fired power plants. 

The EPA also believes that the information provided in the 

proximity analysis will promote engagement between vulnerable 

communities and the agency throughout the rulemaking process. In 

addition to providing the proximity analysis in the docket of 

this rulemaking, the EPA will make it publicly available on its
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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 

The EPA has heard from vulnerable communities throughout

the outreach process for the Clean Power Plan that it is 

imperative for communities to have an understanding of how 

rulemakings that target climate change work. They expressed a 

desire to know how these programs may benefit their communities 

and what the potential adverse impacts of the rules may be on 

their communities. We intend to provide communities with the 

information that they need to engage with the agency throughout 

the comment period. 

We have received feedback from communities that public 

hearings, webinars and in-person meetings are the most effective 

ways to engage with them and to provide them with the 

information that they need to understand the rulemaking process. 

Therefore, for this rulemaking, in addition to conducting public 

hearings for all members of the American public (please see the 

dates section for information on the upcoming public hearings), 

the agency will hold a national webinar for communities in the 
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early stages of the comment period. The goal of this webinar 

will be to walk communities through the highlights of the 

preamble, so they have an understanding of how the rulemaking 

may potentially affect their communities and they will have the 

contextual information they need to actively engage with the 

agency throughout the comment period. 

Additionally, because we received positive feedback on the 

effectiveness of the face-to-face meetings conducted on the 

regional level, each region will be offering an outreach 

meeting(s) for communities. The goal of these meetings is to 

build a level of understanding on this rulemaking to enable 

vulnerable communities to actively engage with the agency 

throughout the comment period. Furthermore, we will follow up on 

common issues raised during the outreach meetings with national 

conference calls, specifically targeted for vulnerable

communities. 

C. Providing Communities with Access to Additional Resources

In section V.D of this preamble, we outline that we are 

seeking comment on whether a portion of this set-aside should be 

targeted to RE projects that benefit low-income communities. 

Furthermore, the EPA is seeking comment on how an low-income

community should be defined as eligible under this set-aside. We 

also seek comment on how much of the set-aside should be 

designated as targeted at over-burdened communities. We also 
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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.

As discussed below, there are also many federal programs 

that can help low-income populations access the benefits of RE, 

EE, and the economic benefits of a cleaner energy economy. 

In the coming months, the EPA will continue to provide 

information and resources for low-income communities on existing 

federal, state, local, and other financial assistance programs 

to encourage EE/RE opportunities that are already available to 

communities. For example the EPA will provide a catalog of 

current or recent state and local programs that have 

successfully helped communities adopt EE/RE measures. The goal 

of these resources is to help vulnerable communities gain the 

benefits of this rulemaking. The use of these RE/EE tools can 

also help low-income households reduce their electricity 

consumption and bills. 

Additionally, as part of the resources that we will be 

providing low-income communities, the EPA will provide 

information on the Adminstration’s Partnerships for Opportunity 

and Workforce and Economic Revitalization (POWER) Initative and 

other programs that specifically target economic development 
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assistance to communities affected by changes in the coal 

industry and the utility power sector.148

D. Federal Programs and Resources Available to Communities

Federal agencies have a history of bringing EE and RE to 

low-income communities. Earlier this summer, the Administration 

announced a new initiative to scale up access to solar energy 

and cut energy bills for all Americans, in particular low- and 

moderate-income communities, and to create a more inclusive 

solar workforce. As part of this new initiative, the U.S. 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 industry for all Americans, 

AmeriCorps is providing funding to deploy solar energy and 

 

148 http://www.eda.gov/power/.
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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 DOE’s Weatherization 

Assistance Program, Health and Human Service’s Low Income Home 

Energy Assistance Program, the Department of Agriculture’s 

Energy Efficiency and Conservation Loan Program, High Cost 

Energy Grant Program, and the Rural Housing Service’s 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 

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 
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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 states 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 

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), 
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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.149 In 

the CSAPR the EPA used its authority to reduce emissions that 

significantly contribute to downwind exposures. The RIA for the 

final CSAPR anticipates substantial health benefits for the 

population across a wide region. Similarly, the EPA believes 

that, like the CSAPR, this rulemaking will result in significant 

health benefits because it will reduce co-pollutant emissions of 

SO2 and NOx on a regional and national basis.150 Thus, localized 

increases in NOx emissions may well be more than offset by NOx

decreases elsewhere in the region that produce a net improvement 

in ozone and particulate concentrations across the area.

Another effect of the final CO2 emission standards for 

affected existing fossil fuel-fired EGUs may be increased 

utilization of other, unmodified EGUs - in particular, high 

 

149 76 FR 48348.

150 76 FR 48347.
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efficiency gas-fired EGUs - with relatively low GHG emissions 

per unit of electrical output. These plants may operate more 

hours during the year and could emit pollutants, including 

pollutants whose environmental effects would be localized and

regional rather than global as is the case with GHG emissions. 

Changes in utilization already occur in response to energy 

demands and evolving energy sources, but the final CO2 emission 

standards for affected existing fossil fuel-fired EGUs can be 

expected to cause more such changes. Increased utilization of 

solid fossil fuel-fired units generally would not increase peak 

concentrations of PM2.5, NOx, or ozone around such EGUs to levels 

higher than those that are already occurring because peak hourly

or daily emissions generally would not change; however, 

increased utilization may make periods of relatively high 

concentrations more frequent. It should be noted that the gasfired sources likely to be dispatched more frequently have very 

low emissions of primary PM, SO2, and HAP per unit of electrical 

output and that they must continue to comply with other CAA 

requirements that directly address the conventional pollutants, 

including federal emission standards, rules included in SIPs, 

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 
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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.”151 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 coal-and NGCC-fired generation, they assumed SO2, 

NOx, PM (and Hg) emissions to be “negligible.” Their studies 

predict NOx emissions from a NGCC unit to be approximately 10 

times lower than a subcritical or supercritical coal-fired 

boiler.152 Many, although not all, NGCC units are also very well 

controlled for emissions of NOx through the application of after 

combustion controls such as selective catalytic reduction. 

F. Assessing Impacts of Federal Plan Implementation 

It is important to the EPA that the implementation of 

federal plans be assessed in order to identify whether they 

cause any adverse impacts on communities already overburdened by 

disproportionate environmental harms and risks. The EPA will 

conduct its own assessment during the implementation phase of 

this rulemaking to determine whether the implementation of 

 

151 65 FR 79831.

152 “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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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 

and communities to monitor any disproportionate emissions that 

may result in adverse impacts and address them. 

G. The EPA’s Continued Engagement 

The EPA is committed to helping ensure that this action 

will not have disproportionate adverse human health or 

environmental effects on vulnerable communities. Throughout the 

implementation phase of this rulemaking, the agency will 

continue to provide trainings and resources to assist 

communities and as they engage with the agency. The EPA, through 

its outreach efforts during the comment period, will continue to 
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solicit feedback from communities on what they would like 

additional trainings and resources on.

As described above, the EPA will assess the impacts of this 

rulemaking during its implementation. The EPA will house this 

assessment, along with the proximity analysis and other 

information generated throughout the implementation process, on 

its Clean Power Plan (CPP) Communities Portal that will be 

linked to this rulemaking’s Web site 

(http://www.epa.gov/cleanpowerplan). In addition, the EPA has 

expanded its set of resources that are being developed to help 

communities understand the breadth of policy options and 

programs that have successfully brought EE/RE to low-income 

communities. The EPA is committed to continuing its engagement 

with communities from the comment period of this rulemaking 

through federal plan implementation.

The EPA consulted its May 2015, Guidance on Considering 

Environmental Justice During the Development of Regulatory 

Actions, when crafting this rulemaking.153 A more detailed 

discussion concerning the application of Executive Order 12898 

in this rulemaking can be found in section X.J of this preamble. 

A summary of the EPA’s interactions with communities is in the 

 

153 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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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 

communities as they engage with the EPA throughout the comment 

period. It will help the EPA as we help low-income communities 

access EE/RE and financial assistance programs. Finally, in 

order to continue to ensure that overburdened communities are 

not disproportionately impacted by this rule, the EPA will be 

conducting an assessment during the implementation phase of the 

effects of this and other rules on air quality. 

X. Statutory and Executive Order Reviews

Additional information about these statutes and Executive 

Orders can be found at http://www2.epa.gov/lawsregulations/laws-and-executive-orders.
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A. Executive Order 12866: Regulatory Planning and Review and 

Executive Order 13563: Improving Regulation and Regulatory 

Review 

This proposed action is an economically significant 

regulatory action that was submitted to the OMB for review. Any 

changes made in response to OMB recommendations have been 

documented in the docket. The EPA prepared an analysis of the 

potential costs and benefits associated with this action. This 

analysis, which is contained in the “Regulatory Impact Analysis 

for the Proposed 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” (EPA-452/R-15-006, July 2015), is 

available in the docket and is briefly summarized in section 

VIII of this preamble. 

Consistent with Executive Order 12866 and Executive Order 

13563, the EPA estimated the costs and benefits for two 

alternative federal plan approaches to 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 
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to as co-benefits, as these reductions are not the primary 

objective of this rule.

The RIA for this proposal analyzed two implementation 

scenarios, which we term the “rate-based federal plan approach”

and the “mass-based federal plan approach”. It is very important 

to note that the differences between the analytical results for 

the rate-based and 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 

performs differently than the other on a given metric during a 

given time period, this does not imply this will apply in all 

instances.

It is important to note that the potential regulatory 

impacts presented in the Clean Power Plan Final Rule RIA and the 

RIA for this proposed rule are not additive. Both RIAs present 

estimates of the benefits and costs of achieving the emission 

performance rates of the Clean Power Plan EGs. In the case of 

the Clean Power Plan Final Rule RIA, the illustrative analysis 

assumes the performance rates are met under state plans. In the 

case of this RIA for the proposed federal plan and model trading 

rules, the same performance rates are accomplished but are 

assumed to be achieved under the federal plan or model trading 

rules.
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The EPA has used the social cost of carbon estimates 

presented in the Technical Support Document: Technical Update of 

the Social Cost of Carbon for Regulatory Impact Analysis Under 

Executive Order 12866 (May 2013, Revised July 2015) (“current 

TSD”) to analyze CO2 climate impacts of this rulemaking. We refer 

to these estimates, which were developed by the U.S. government, 

as “SC-CO2 estimates.” The SC-CO2 is an estimate of the monetary 

value of impacts associated with a marginal change in CO2

emissions in a given year. The four SC-CO2 estimates are 

associated with different discount rates (model average at 2.5 

percent discount rate, 3 percent, and 5 percent; 95th percentile 

at 3 percent), and each increases over time. In this summary, 

the EPA provides the estimate of climate benefits associated 

with the SC-CO2 value deemed to be central in the current TSD: 

the model average at 3 percent discount rate. 

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 
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$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 

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 
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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 

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 
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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.

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
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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 

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
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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.

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 
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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 

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)

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 EPA 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 
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Indian country. This rule does impose specific requirements on 

EGUs located in states, U.S. territories or areas of Indian 

country.

The information collection activities in this proposed rule 

are consistent with those activities defined under the Carbon 

Pollution Emission Guidelines for Existing Stationary Sources: 

Electric Utility Generating Units ([insert FR number]; the Clean 

Power Plan) finalized on August 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 ICR document prepared by the EPA has been assigned EPA ICR 

number 2526.01. 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 
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requirements in the NSPS General Provisions (40 CFR part 60, 

subpart A), which are mandatory for all owners/operators subject 

to CAA section 111 national emission standards, there are no new 

information collection costs, as the information required by 

this proposed rule is already collected and reported by other 

regulatory programs. The recordkeeping and reporting 

requirements are specifically authorized by CAA section 114 (42 

U.S.C. 7414). All information submitted to the EPA pursuant to 

the recordkeeping and reporting requirements for which a claim 

of confidentiality is made is safeguarded according to agency 

policies set forth in 40 CFR part 2, subpart B.

Although 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.
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Estimated number of respondents: Unknown at this time, but 

have assumed all affected entities are respondents for an upper 

bound estimate. 

Frequency of response: None, no responses are required 

during the period covered by the ICR.

Total estimated burden: 17,133 hours (per year). Burden is 

defined at 5 CFR 1320.3(b).

Total estimated cost: $1,706,501 (per year)

An agency may not conduct or sponsor, and a person is not 

required to respond to, a collection of information unless it 

displays a currently valid OMB control number. The OMB control 

numbers for the EPA’s regulations in 40 CFR are listed in 40 CFR 

part 9.

Submit your comments on the agency’s need for this 

information, the accuracy of the provided burden estimates and 

any suggested methods for minimizing respondent burden to the 

EPA using the docket identified at the beginning of this rule. 

You may also send your ICR-related comments to OMB’s Office of 

Information and Regulatory Affairs via email to 

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 
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the Federal Register]. The EPA will respond to any ICR-related 

comments in the final rule.

C. Regulatory Flexibility Act (RFA)

Pursuant to section 603 of the RFA, the EPA prepared an 

initial regulatory flexibility analysis (IRFA) that examines the 

impact of the proposed rule on small entities along with 

regulatory alternatives that could minimize that impact. The 

complete IRFA is available for review within the RIA in docket

EPA-HQ-OAR-2015-0199 and is summarized 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 
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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 

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.
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As noted earlier, there are 74 small entities with 

potentially affected EGUs that are modeled in the IPM base case 

in 2030. Of these, 24 small entities are projected to withdraw 

all of their potentially affected EGUs from operation under base 

case conditions. This leaves 50 small entities with potentially 

affected EGUs that are projected to be generating electricity in 

2030. Under the rate-based federal plan approach, 7 of these 50 

small entities are projected to withdraw all of their 

potentially affected EGUs from operation by 2030. Under the 

mass-based federal plan approach, 5 of these 50 small entities 

are projected withdraw all of their potentially affected EGUs 

from operation by 2030.

Under the rate-based federal plan approach, 23 small 

entities are projected to incur net compliance costs greater 

than 3 percent of generation revenues from their potentially 

affected EGUs. In contrast, 9 entities are estimated to have net 

compliance cost savings greater than 3 percent of their 

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. 
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There are uncertainties and limitations in this analysis 

that may result in estimates that diverge from what we might see 

in reality. For example, at the time of this proposal, the EPA 

has no information on whether any or how many states will 

require a federal plan. The rate-based and mass-based federal 

plan approaches analyzed in this IRFA are based on a scenario 

where all states of the contiguous U.S. will be regulated under 

a federal plan. Another factor to consider is that entities 

operating in regulated or cost-of-service markets are likely 

able to recover compliance costs through rate adjustments; as a 

result these costs can be viewed as likely being over-estimates 

for this set of utilities. Other uncertainties and data 

limitations exist and are described in the complete IRFA 

available for review within the RIA.

As discussed earlier in this preamble, the reporting, 

recordkeeping and other compliance requirements are most likely 

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 
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modified and reconstructed fossil fuel fired EGUs, in addition 

to the Clean Power Plan EGs, to cut carbon pollution from 

existing fossil fuel fired EGUs. These existing EGUs are, or 

will be, potentially impacted by several other recently 

finalized EPA rules. On February 16, 2012, the EPA issued the 

mercury and air toxics standards (MATS) rule (77 FR 9304) to 

reduce emissions of toxic air pollutants from new and existing 

coal- and oil-fired EGUs. On May 19, 2014, the EPA issued a 

final rule under section 316(b) of the Clean Water Act (33 

U.S.C. 1326(b)). This rule establishes new standards to reduce 

injury and death of fish and other aquatic life caused by 

cooling water intake structures at existing power plants and 

manufacturing facilities. On June 18, 2014 (79 FR 34830), the 

EPA promulgated the stream electric effluent limitation 

guidelines (SE ELG) rule to strengthen the controls on 

discharges from certain steam electric power plants. 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 
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that potentially would be subject to the rule's requirements. 

The SBAR Panel evaluated the assembled materials and smallentity comments on issues related to elements of an IRFA. A copy 

of the full SBAR Panel Report is available in the rulemaking 

docket.

The EPA also considered whether the separate changes that 

we are proposing to make, as explained in section VII of this 

preamble above, to the framework regulations in subpart B of 

part 60 of the CAA regulations would have any impacts on small 

entities. Since these changes only modify and enhance the 

procedures that the Administrator will follow in processing 

state plans and promulgating a federal plan, and do not alter 

the rules or requirements that states or regulated entities must 

follow, the agency does not believe that there will be economic 

impacts on small entities from this portion of this proposal. 

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) 

This action contains a federal mandate under UMRA, 2 U.S.C. 

1531-1538, that could potentially result in expenditures of $100 

million or more for state, local, and tribal governments, in the 

aggregate, or the private sector in any 1 year. This federal 
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plan will apply only to those EGUs located in states that do not 

submit approvable state plans, which is a subset of the EGUs 

considered in the RIA for 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 is not subject to the requirements of section 203 of 

UMRA because it contains no regulatory requirements that might 

significantly or uniquely affect small governments. 

Nevertheless, the EPA is aware that there is substantial 

interest in this rule among small entities (e.g., municipal and 

rural electric cooperatives). In light of this interest, prior 

to this action, the EPA sought early input from representatives 

of small entities while formulating the provisions of the 

proposed regulation. Such outreach is also consistent with the 

President’s January 18, 2011 Memorandum on Regulatory 

Flexibility, Small Business, and Job Creation, which emphasizes 
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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

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 EGs to permit them to have 

meaningful and timely input into its development. As described 

in the Federalism discussion in the preamble to the proposed 

standards of performance for GHG emissions from new EGUs (79 FR 

1501; January 8, 2014), the EPA consulted with state and local 

officials in the process of developing the proposed standards 
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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 Clean Power Plan EGs, as required by section 6(b) of 

Executive Order 13132. In the spirit of Executive Order 13132, 

and consistent with the EPA’s policy to promote communications 

between the EPA and state and local governments, the EPA 

specifically solicits comment on this proposed action from state 

and local officials.

F. Executive Order 13175: Consultation and Coordination with 

Indian Tribal Governments

This proposed action has tribal implications. However, it 

will neither impose substantial direct compliance costs on 

federally recognized tribal governments, nor preempt tribal law. 

The EGU potentially impacted by this proposed rulemaking located 

on Indian reservations are primarily owned by private entities, 

and in one case, partially owned by an agency of the U.S.

government. As a result, the tribes on whose areas of Indian 

country those units are located will not be directly impacted by 

any costs of complying with this proposed rulemaking incurred by 

the owners/operators of those units. There would only be tribal 

implications in regards to compliance costs associated with this 

proposed rulemaking in the case where a tribal government has an 

ownership interest in a potentially affected EGU. A tribal 
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government could also incur costs in the event that it seeks and 

is given delegated authority to enforce the federal plan 

proposed in this rulemaking. The EPA has, nevertheless, offered 

consultation to the tribes on whose areas of Indian country the 

units are located. As part of its general outreach to tribes 

regarding this proposed rulemaking, the EPA received feedback 

from a number of tribes regarding the potential overall economic 

impact that both the proposed Clean Power Plan and a proposed 

federal 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. 

Additionally, the EPA held consultations for tribes shortly 

following the release of the supplemental proposal. The agency 

also held a public hearing on the supplemental proposal on 

November 19, 2014, in Phoenix, Arizona. At the public hearing 

the agency received oral comments from community members 

representing a number of tribes and a number of tribal 
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officials. 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 EGs. 

Additionally, the EPA engaged in meaningful dialogue with 

tribal stakeholders to obtain their feedback in the pre-proposal 

stages of this rulemaking. We provided an update on this 

proposed rulemaking on the May 28, 2015, National Tribal Air 

Association 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 federal plan. 

Consistent with previous rulemakings impacting the power 

sector, there is significant tribal interest in these 

rulemakings because of the potential indirect impacts that rules 

such as the Clean Power Plan and this proposed federal plan may 

have on tribes. The EPA specifically solicits additional 

feedback from tribal officials on all aspects of this proposed 

rulemaking, including whether tribes whose areas of Indian 

country contain affected EGU(s) are interested in developing 

their own plan implementing the final EGs. Additionally, tribal 

stakeholders will be included in the outreach that the agency 

will be conducting with those communities already overburdened 

by pollution, which are often low-income communities, 
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communities of color, and indigenous communities. The actions 

that the agency will be taking are outlined in section 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

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 
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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 (59 FR 7629; February 16, 1994) 

establishes federal executive policy on EJ. Its main provision 

directs federal agencies, to the greatest extent practicable and 

permitted by law, to make EJ 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 EJ 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 
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be achieved when everyone enjoys the same degree of protection 

from environmental and health hazards and equal access to the 

decision-making process to have a healthy environment in which 

to live, learn, and work.

Leading up to this rulemaking the EPA summarized the public 

health and welfare effects of GHG emissions in its 2009 

Endangerment Finding. As part of the Endangerment Finding, the 

Administrator considered climate change risks to minority 

populations and low-income populations, finding that certain 

parts of the population may be especially vulnerable based on 

their characteristics or circumstances. Populations that were 

found to be particularly vulnerable to climate change risks 

include the poor, the elderly, the very young, those already in 

poor health, the disabled, those living alone, and/or indigenous 

populations dependent on one or a few resources. See sections 

X.F and X.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, the Intergovernmental 

Panel on Climate Change (IPCC), and the National Research 
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Council of the National Academies that the potential impacts of 

climate change raise EJ issues. These reports concluded that 

poor communities can be especially vulnerable to climate change 

impacts because they tend to have more limited adaptive 

capacities and are more dependent on climate-sensitive resources 

such as local water and food supplies. In addition, Native 

American tribal communities possess unique vulnerabilities to 

climate change, particularly those impacted by degradation of 

natural and cultural resources within established reservation 

boundaries and threats to traditional subsistence lifestyles. 

Tribal communities whose health, economic well-being, and 

cultural traditions that depend upon the natural environment 

will likely be affected by the degradation of ecosystem goods 

and services associated with climate change. The 2009 

Endangerment Finding record also specifically noted that 

Southwest native cultures are especially vulnerable to water 

quality and availability impacts. Native Alaskan communities are 

already experiencing disruptive impacts, including coastal 

erosion and shifts in the range or abundance of wild species 

crucial to their livelihoods and well-being. 

The most recent assessments continue to strengthen 

scientific understanding of climate change risks to minority 
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populations and low-income populations in the U.S.154 The new 

assessment literature provides more detailed findings regarding 

these populations’ vulnerabilities and projected impacts they 

may experience. In addition, the most recent assessment reports 

provide new information on how some communities of color may be 

uniquely vulnerable to climate change health impacts in the U.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 EJ 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 

 

154 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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particular threats to health, well-being, and ways of life of 

indigenous peoples in the U.S.

As the scientific literature presented above and as the 

2009 Endangerment Finding illustrates, low income populations 

and some communities of color are especially vulnerable to the 

health and other adverse impacts of climate change. The EPA 

believes that communities will benefit from this proposed 

federal plan because this action directly addresses the impacts 

of climate change by limiting GHG emissions through the 

establishment of CO2 emission standards for existing affected 

fossil fuel-fired EGUs. 

In addition to reducing CO2 emissions, the guidelines 

finalized in this rulemaking would reduce other emissions from 

affected EGUs that reduce generation due to higher adoption of 

EE and RE. These emission reductions will include SO2 and NOx, 

which form ambient PM2.5 and ozone in the atmosphere, and HAP, 

such as mercury and hydrochloric acid. In the final rule 

revising the annual PM2.5 NAAQS,155 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 

 

155 “National Ambient Air Quality Standards for Particulate Matter, Final 

Rule,” 78 FR 3086 (Jan. 15, 2013).
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treatment, and increased nutritional deficiencies, which can 

increase this population’s susceptibility to PM-related 

effects.156 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. 

Additionally, as outlined in the community and EJ

considerations section IX of this preamble, the EPA has taken a 

number of actions to help ensure that this action will not have 

potential disproportionately high and adverse human health or 

environmental effects on vulnerable communities. The EPA 

consulted its May 2015, Guidance on Considering Environmental 

Justice During the Development of Regulatory Actions, when 

determining what actions to take.157 As described in the 

community and EJ considerations section of this preamble the EPA 

also conducted a proximity analysis, which is available in the 

 

156 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.

157 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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docket of this rulemaking and is discussed in section IX of this 

preamble. Additionally, as outlined in sections I and IX of this 

preamble the EPA has engaged meaningfully with communities 

throughout the development of the CPP and has devised a robust 

outreach strategy for continual engagement throughout this 

rulemaking.
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 455 of 455

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.