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Review***

 EO12866_CPP Federal Plan 2060 AS47 NPRM_20150729 

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 emission guidelines (EGs) for existing fossil fuel-fired 

electric generating units (EGUs) under the Clean Air Act (CAA). 

The EGs were proposed in June 2014 and finalized on [&&&] as the 

Carbon Pollution Emission Guidelines for Existing Stationary 

Sources: Electric Utility Generating Units (also known as the 

Clean Power Plan). 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 
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proposals also constitute proposed model trading rules that 

states can adopt or tailor for implementation of the 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 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 carbon dioxide 

(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 
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in summer 2016. 

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 XXX [insert number of 

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

hearings will be held to accept oral comments on the proposed 

federal plan. The hearings will be held[insert number, days of 

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

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

time). 

ADDRESSES: Submit your comments on the federal plan requirements 

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

by one of the following methods: 

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

Follow the online instructions for submitting 

comments. 

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

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

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

• Mail: Send your comments to: 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. 
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• 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-HQ-OAR-2015-0199. Such 

deliveries are accepted only during the Docket’s 

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

Monday through Friday, excluding legal holidays) and 

special arrangements should be made for deliveries of 

boxed information. 

Instructions: Direct your comments on the federal plan 

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

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

included in the public docket and may be made available online 

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

information provided, unless the comment includes information 

claimed to be confidential business information (CBI) or other 

information whose disclosure is restricted by statute. Do not 

submit information that you consider to be CBI or otherwise 

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

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

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

contact information unless you provide it in the body of your 

comment. If you send an email comment directly to the EPA 

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, 
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the EPA recommends that you include your name and other contact 

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

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

technical difficulties and cannot contact you for clarification, 

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

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

encryption and be free of any defects or viruses. 

Public Hearing: XXX [insert number of hearings 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 XXXX at (919) 541–XXXX. 

The last day to pre-register to speak at the hearings will be 

XXX, 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 
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guarantee that we can accommodate all timing requests and will 

provide requestors with the next available speaking time, in the 

event that their requested time is taken. Please note that the 

time outlined in the confirmation email received will be the 

time the one will be scheduled to speak. Again, depending on the 

flow of the day, times may fluctuate. If you require the service 

of a translator or special accommodations such as audio 

description, we ask that you pre-register for the hearings by 

XXX, 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 XXXX at (919) 541–XXXX 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 
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during the comment period will be considered with the same 

weight as oral comments and supporting information presented at 

the public hearing. Verbatim transcripts of the hearing and 

written statements will be included in the docket for the 

rulemaking. The EPA plans for the hearings to run on schedule; 

however, due to on-site schedule fluctuations, actual speaking 

times may shift slightly. 

 Because these hearings are being held at 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 
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in the building, cameras may only be used outside of the building, 

and demonstrations will not be allowed on federal property for 

security reasons. 

 Attendees will be asked to go through metal detectors. To 

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

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

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

devices from their carrying case and place in provided bins for 

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

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

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

of the guard if identified for secondary screening. Additionally, 

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

(e.g., marijuana) will be allowed in the building. We recommend 

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

disclosure is restricted by statute. Certain other material, 

such as copyrighted material, will be publicly available only in 

hard copy form. Publicly available docket materials are 

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

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

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

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

Monday through Friday, excluding holidays. The telephone number 

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

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

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

Incineration Group, Sector Policies and Programs Division 

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

Park, North Carolina 27711; telephone number: (919) 541-0316; 

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

SUPPLEMENTARY INFORMATION: 

Acronyms and Abbreviations. The following acronyms and 

abbreviations are used in this document. 

AG Attorney General 

ANSI American National Standards Institute 

ASME American Society of Mechanical Engineers 

ASTM American Society of Testing and Materials 

CAA Clean Air Act 
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CBI Confidential Business Information 

CDX Central Data Exchange 

CFR Code of Federal Regulations 

CAIR Clean Air Interstate Rule 

CO2 Carbon dioxide 

CSAPR Cross-state Air Pollution Rule 

EE 

EG Emission Guidelines 

eGRID Emissions & Generation Resource Integrated Database 

EGU Electric Generating Unit 

EIA Energy Information Administration 

EJ Environmental Justice 

EM&V Evaluation, Measurement, and Verification 

EPA Environmental Protection Agency 

FIP Federal Implementation Plan 

GHG Greenhouse Gas 

IGCC Integrated Gasification Combined Cycle Unit

HAP Hazardous Air Pollutants 

MWh Megawatt Hours 

NAAQS National Ambient Air Quality Standards 

NAICS North American Industrial Classification System 

NEEDS National Electric Energy Data System 

NTAA National Tribal Air Association 

NOX Nitrogen Oxides 

OAP Office of Atmospheric Programs 

OAQPS Office of Air Quality Planning and Standards 

PPA Power Purchase Agreement 

PRA Paperwork Reduction Act 

PV Photovoltaics 

RE 

RFA Regulatory Flexibility Act 

RGGI Regional Greenhouse Gas Initiative 

SBA Small Business Administration 

SCT Stationary Combustion Turbine 
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SGU Steam Generating Unit 

SIP State Implementation Plan 

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

Circuit 

TTN Technology Transfer Network 

UMRA Unfunded Mandates Reform Act of 1995 

UNFCCC United Nations Framework Convention on Climate Change 

WWW Worldwide Web 

Organization of This Document. The following outline is provided 

to aid in locating information in this preamble. 

I. General Information

A. Executive Summary

B. Organization and Approach for this Proposed Rule

C. Who Does the Proposed Action Apply to?

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

II. Background Information

A. What is the Regulatory Development Background for this 

Proposed Rule?

B. What is the Purpose of this Proposed Rule?

C. Legal Authority

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

Plan, and other Proposed Actions

E. Use of the Model Trading Rule as a Backstop

III. Federal Plan Structure to Achieve Reductions 

A. Overview

B. Inventory of Emissions

C. Affected EGUs

D. Compliance Schedule

E. Addressing Reliability Concerns

F. Worker Certification

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

H. Implications for Other EPA Programs and Rules

I. Administrative Appeals Process
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J. Consistency of Program Structure with Clean Air Act Authority

IV. Rate-based Implementation Approach 

A. Overview

B. Rate Goals

C. Crediting Mechanism

D. ERC Tracking and Compliance Operations

E. Federal Plan and State Plan Interactions

V. Mass-based Implementation Approach 

A. Trading Program Overview 

B. Statewide Mass-based Emissions Goals

C. Compliance Timing and Allowance Banking

D. Initial Distribution of Allowances

E. State-determined Allowance Distribution

F. Treatment of States Entering or Exiting the Trading Program

G. Allowance Tracking, Compliance Operations, and Penalties

H. Emissions Monitoring and Reporting Requirements

VI. Implementation of the Federal Plan and Delegation

A. Delegation of the Federal Plan and Retained Authorities

B. Mechanisms for Transferring Authority

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? 
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C. What are the Energy Impacts? 

D. What are the Compliance Costs?

E. What are the Economic and Employment Impacts? 

F. What are the Benefits of the Proposed Action? 

IX. Community and Environmental Justice Considerations

A. Proximity Analysis

B. Community Engagement in This Rulemaking Process

C. Providing Communities with Access to Additional Resources

D. Federal Programs and Resources Available to Communities

E. Co-Pollutants

F. Assessing Impacts of Federal Plan Implementation

G. The EPA’s Continued Engagement

X. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and 

Executive Order 13563: Improving Regulation and Regulatory 

Review 

B. Paperwork Reduction Act (PRA)

C. Regulatory Flexibility Act (RFA)

D. Unfunded Mandates Reform Act (UMRA)

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
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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 has promulgated these EGs under CAA section 

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

for the EGUs at certain large fossil fuel-fired power plants 

(“affected EGUs”), which the states then apply to their sources 

through implementation of state plans. At this point, the 

responsibility shifts to the states who can submit plans to 

achieve these emission performance levels for EPA approval, or 

initial submittalinitial submittals, by September 6, 2016. The 

amount of reductions in CO2 that the EPA has 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 
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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 

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

doing that. 

Accordingly, the EPA proposes a federal plan under section 

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

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 
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implementing emission standards for a state’s affected EGUs. 

Both proposed approaches to the federal plan would require 

affected EGUs to meet emission standards set using the CO2

emission performance rates in the EGs. The federal plan will 

achieve the same levels of emissions performance as required of 

state plans under the EGs. The EPA will only promulgate a final 

federal plan for 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 

potential use by any state. The regulatory text of each federal 

plan and the corresponding model trading rule is identical, 

except as indicated otherwise within the text of the model rule 

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

to use related to the crediting of a broader set of clean energy 

resources than is being proposed in the federal plan). 

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

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

state does not submit an approvable plan by the deadlines 

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

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

submitted plan because it does not meet the requirements of the 

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

for their sources rather than undertake the development of a 

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

proposed rule, a federal plan promulgated for a particular state 

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

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

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

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

 

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

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

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

when referring to this proposed federal plan also is intended to 

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

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

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

NOx Budget Trading Program, the CAIR, and the CSAPR, where a single 

rule promulgated multiple FIPs. 
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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 when we 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 

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

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

applicable under the Clean Power Plan and other CAA section 

111(d) rules. These changes clarify the availability of certain 

procedural mechanisms similar to those available under CAA 

section 110 (such as calls for plan revisions and the 

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

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

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

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

requirements established in the EGs. 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 
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extensive consideration to impacts on vulnerable communities, 

particularly low-income communities, communities of color, and 

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 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 
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create a level of flexibility for affected EGUs that allows 

owners and operators to determine the best way to achieve 

emissions reductions, at the EGU-, state-, multi-state-, 

regional-, or national level. As a result, compliance strategies 

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

current electricity grid as it continues to serve its primary 

critical function of ensuring an uninterrupted supply of 

affordable and reliable electricity. This flexibility is 

especially valuable whenever the need to address specific 

reliability concerns arises. It allows owners and operators of 

reliability-critical EGUs to continue to meet their compliance 

obligations while operating to maintain electric reliability. 

The EPA outlined and initiated the Clean Energy Incentive 

Program (CEIP) in the final emission guidelines (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 that 

benefit low-income communities, that generate MWh or reduce enduse energy demand during 2020 and 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 ensu environmental integrity of the 
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program as well as avoid unintended environmental impacts. We 

took measures to ensure that the reductions in carbon emissions 

this plan will achieve are real, and not just apparent. As in 

the EGs, in both the rate- and mass-based approaches, the EPA 

has incorporated components to address the concern that the 

dynamics of either a rate- or mass-based trading program could 

incentivize shifting generation from existing units in ways that 

would result in more CO2 emissions than would otherwise be 

expected, or that undermine the purpose of the CAA section 

111(d) program. 

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 
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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 

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 considerations section IX.B of this 

preamble. 

B. Organization and Approach for this Proposed Rule 

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

implement the Clean Power Plan EGs for affected fossil fuelfired EGUs operating in states that do not have approved state 
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plans. Specifically, the EPA is co-proposing two different 

approaches to a federal plan to implement the Clean Power Plan 

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

approach. While establishing emission standards for affected 

EGUs that would be directly enforceable against the owners and 

operators of the source, both approaches would grant EGUs 

substantial flexibility in meeting their compliance obligations. 

For this reason, among others, these proposed approaches also 

serve as two proposed model trading rules that states may adopt 

or tailor in designing their own plans. 

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 
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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. We invite comment on which 

approach would be appropriate to finalize for all states. 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 

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

has taken final action on the BSER for CO2 emissions from 

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

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

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

The second approach to a federal plan that the EPA is 

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

 

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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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 renewable energy 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 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. 
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C. Who Does the Proposed Action Apply to? 

Regulated Entities. Existing fossil fuel-fired electric 

generating units (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 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. 

 

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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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 

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 

 

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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a steam generating unit (SGU) or IGCC, must serve a generator 

capable of selling greater than 25 MW to a utility power 

distribution system, have a base load rating greater than 260 

GJ/hr (250 MMBtu/hr) 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 power 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/hr), and historically have 

combusted more than 90 percent natural gas on a heat input basis 

on 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 EPA-

 

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

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

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 

 

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. 

7 Presidential Memorandum—Power Sector Carbon Pollution Standards, 

June 25, 2013. http://www.whitehouse.gov/the-pressoffice/2013/06/25/ presidential-memorandum-power-sectorcarbonpollution-standards. 
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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 

address: 

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

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

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

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

or CD-ROM the specific information that is claimed as CBI. In 
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addition to one complete version of the comment that includes 

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

contain the information claimed as CBI must be submitted for 

inclusion in the public docket. Information marked as CBI will 

not be disclosed except in accordance with procedures set forth 

in 40 CFR part 2. 

If you have any questions about CBI or the procedures for 

claiming CBI, please consult the person identified in the FOR 

FURTHER INFORMATION CONTACT section. 

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

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

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

docket, an electronic copy of the proposed action is available 

on the 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 

proposed action at http://www.epa.gov/airtoxics/XX. Following 

publication in the Federal Register, the EPA will post the 

Federal Register version of the proposed rule and key technical 

documents on the same Web site. 
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II. Background Information 

A. What is the Regulatory Development Background for this 

Proposed Rule?

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

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

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

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

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

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

guidelines are required to submit to the EPA by 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 &&&).8 As discussed in section VI.D of this preamble, 

Indian Tribes may, but are not required to, submit tribal plans. 

Once the EPA finds that a state has failed to submit a plan, or 

disapproves a state plan,9 section 111 of the CAA and 40 CFR 

 

8 See Section VII of this preamble for additional information on 

proposed changes to 40 CFR 60.27 to provide enhancements and 

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

state plans and promulgation of federal plans. 

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

through a public notice and comment process to fully or partially 

approve or disapprove the state plan. 
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60.27 require the EPA to develop, implement, and enforce a 

federal plan for existing EGUs located in that state. In 

addition, CAA section 301(d)(2) authorizes the Administrator to 

treat an Indian Tribe in the same manner as a state for this EGU 

requirement. See 40 CFR 49.3; see also “Indian Tribes: Air 

Quality Planning and Management,” hereafter “Tribal Authority 

Rule,” (63 FR 7254, February 12, 1998). As discussed in section 

VI.D of this preamble, the agency in this action is proposing a 

necessary or appropriate finding for the affected EGUs in 

several areas of Indian country and is proposing the federal 

plan for these affected EGUs. 

The agency believes it is appropriate to propose the 

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

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

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

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

that congressionally mandated emission standards under authority 

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

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

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

proposal also serves as two proposed model trading rules which 

states can adopt or tailor for adoption as their state plan. The 

role of the model rules is discussed in the following section. 
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In this proposal, the EPA is soliciting public comment only 

on the proposed approaches for a federal plan and model trading 

rule for the implementation of the Clean Power Plan EGs. 

Comments on the underlying Clean Power Plan rule will be 

considered out of scope for this action. 

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 EG for existing EGUs. States with affected EGUs 

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

by September 6, 2016 pursuant to the EGs.10 States without any 

existing EGUs are directed to submit to the Administrator 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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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 

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 
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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 

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 
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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 VI.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 

model trading rules. Ultimately, state plans must meet the 

requirements of the EGs for approvability. Thus, a conditional 
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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 

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

Call model rule at 40 CFR part 96 (63 FR 57356; Oct. 27, 1998) 

was identical in all meaningful respects with the Federal NOx

Budget Trading Program at 40 CFR part 97 (65 FR 2674; Jan. 18, 

2000). And the Clean Air Interstate Rule (CAIR) model rule in 40 

CFR part 96 (70 FR 25339; May 12, 2005) was identical in all 

meaningful respects with the federal CAIR in 40 CFR part 97 (71 

FR 25396; April 28, 2006).11 While these identical programs for 

 

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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model rules and FIPs were 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 cross-reference, 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 [&&&] [&&&] Connecticut, 

Massachusetts, 

Maine, New 

Hampshire, Rhode 

Island, Vermont 

Region II New York, New 

Jersey, Puerto 

Rico, Virgin 

Islands 

Region III Virginia, 

Delaware, 

District of 

Columbia, 

Maryland, 

 

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 

Pennsylvania, 

West Virginia 

Region IV 

 

 Florida, Georgia, 

North Carolina, 

Alabama, 

Kentucky, 

Mississippi, 

South Carolina, 

Tennessee 

Region V 

 

 Minnesota, 

Wisconsin, 

Illinois, 

Indiana, 

Michigan, Ohio 

Region VI 

 

&&& &&& Arkansas, 

Louisiana, New 

Mexico, Oklahoma, 

Texas 

Region VII &&& &&& Iowa, Kansas, 

Missouri, 

Nebraska 

Region VIII 

 

&&& &&& Colorado, 

Montana, North 

Dakota, South 

Dakota, Utah, 

Wyoming 

Region IX &&& &&& Arizona, 

California, 

Hawaii, Nevada, 

American Samoa, 

Guam, Northern 
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Region Regional contact Phone 

States and 

protectorates 

Mariana Islands 

Region X &&& &&& 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 

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

seek a two 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 
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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. 

 

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

Plan, and other Proposed Actions 

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

both of which also constitute proposed model trading rules that 

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

currently intends to finalize one or both of the model trading 

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

soon as possible to help inform their state plan development 

efforts prior to the initial submittal deadline of September 6, 

2016, and two years before the states’ final plan deadline of 

September 6, 2018.14 If the EPA finalizes the model trading rules 

in that timeframe, the only direct consequence will be to 

provide the states certainty as to one or two particular 

approaches to the design of their state plan that the EPA will 

approve if adopted in full. The finalization of a 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 

 

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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has made a finding on a state’s failure to submit a plan, or 

fully or partially disapproved a submitted state plan. The EPA 

will go through a public notice and comment process before 

disapproving a submitted and complete state plan, in whole or 

part. The EPA invites comments on this staged approach to 

finalizing one or more model trading rules on the one hand 

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

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

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

plans). 

In this action, the EPA is also proposing enhancements to 

the process for agency action on state submittals and 

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

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

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

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

finalize these changes on a timeline earlier than both a model 

trading rule and the federal plan. 

Under the framework regulations and the final EGs, at 40 

CFR part 60.27 and &&&60.5715 and &&&5760, respectively, the 

initial timelines for EPA action on state submittals and, 

potentially, the promulgation of a federal plan will be as 

follows: the EPA will have 12 months from the date of a state's 
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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 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 
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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

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 
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free - and the EPA in fact encourages states - to submit state 

plans that can replace the federal plan. States can do so in 

advance of the beginning of the performance period in 2022, or 

may transfer to a state plan after that date. However, in doing 

so, the agency and states should be mindful of the goals of 

regulatory certainty discussed in the prior paragraph. 

Because we are proposing a federal plan that would apply 

emission standards to affected EGUs in all states that the 

agency determines not to have an approvable plan, the EPA 

invites comment from all persons with concerns about or comments 

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

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

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

In this 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. 

 

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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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 

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

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

E. Use of the Model Trading Rule as a Backstop 

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

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

rule could function well as the federally enforceable “backstop” 

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

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 

 

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

federally enforceable backstop in a state measures approach are 

discussed in detail in the final EGs. See &&§ion VIII.C.4.b 

and &&&VIII.C.4.c.2 of the final EGs. To summarize those 

provisions, without reopening them for comment, the federally 

enforceable backstop must fully achieve the CO2 emission 

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

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

emission performance. The state plan submittal must identify the 

federally enforceable emission standards for affected EGUs that 

would be used in the backstop, demonstrate that those emission 

standards meet the requirements that apply in the context of an 

emission standards approach, identify a schedule and trigger for 

implementation of the backstop that is consistent with the 

requirements in the EGs, and identify all necessary state 

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

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

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

a minimum of changes necessary to make the rule appropriate for 

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

Instances of this approach are throughout the proposed rule text 

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

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

measures” plan. 

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

model trading rules proposed in this action is the requirement 

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

prior plan performance period. The model trading rules do not 

provide provisions that would automatically adjust the emission 

standards to account for any prior emission performance 

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 
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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 EPAadministered, 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. 

1. Applicability and Enforceability 

If promulgated for the affected EGUs in a particular state, 

this federal plan will require affected EGUs to meet specific 

emission standards for CO2 and related requirements. These 

enforceable compliance obligations will apply to the owners and 

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

 

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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III. Federal Plan Structure to Achieve Reductions 

A. Overview 

1. Interactions with State Plans and Scope of Trading 

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

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

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

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

compliance instruments with affected EGUs in any other state 

covered by a federal plan that uses the same approach. In the 

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

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

could use, as a compliance instrument, an allowance distributed 

in any other state covered by the federal plan. Similarly, in 

the proposed rate-based federal-plan trading program approach, 

this would mean that affected EGUs in a state covered by the 

federal plan could use, as a compliance instrument, an ERC 

issued in any other state covered by 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-for-interstate-
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trading” plans in the EGs. The EPA is proposing the federal 

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

• 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 
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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 

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 
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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 

conversion occurs. The agency requests comment on these and any 

other considerations for linkages between the federal plan and 
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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 

state plans could result in linking of the federal plan to state 

 

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

otherwise noted. 
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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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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 (e.g., the rate-based and 

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

sources, beyond the emissions expected from new sources if 

existing EGUs were given standards of performance in the form of 

the subcategory-specific emission performance rates. The final 

EGs specified that mass-based plan approaches must address 

leakage, because the nature of the mass goals would create 

differing incentives to run for affected existing EGUs and for 

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

producing more emissions. These circumstances are much less 

likely to be present under a rate-based plan approach, where 

both affected EGUs and new sources face similar incentives to 

run. By requiring plan components that address leakage, the 

final EGs ensure that mass goals are an equivalent alternative 

to the subcategory CO2 performance rates and the rate-based state 

goals. 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 plan components that 

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

approach under the federal plan and model rule, to implement 
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allowance allocation approaches to address leakage, specifically 

through establishing an output-based allocation set-aside and a 

set-aside that encourages the installation of RE. These proposed 

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

In the final EGs, the EPA also discussed the concern that 

CO2 emissions reductions would be eroded in situations where an 

affected EGU in a rate-based state counts the MWh from measures 

located in a mass-based state, but the generation from that 

measure acts solely to serve load in the mass-based state. In 

that scenario, expected CO2 emission reduction actions in the 

rate-based state are foregone as a result of counting MWh that 

resulted in CO2 emission reductions in a mass-based state. The 

proposed rate-based approach, in accordance with the final 

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 
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through the provision of a power delivery contract or power 

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

contracts for the supply of the MWhs in question and providing 

documentation that the electricity was treated as comparable to 

a generation resource used to serve regional load that included 

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

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

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

project is approved, subsequent applications for issuance of 

credit to the EPA will need to reference that the megawatt-hours 

submitted are associated with that contractual arrangement with 

the mass-based RE provider. The EPA requests comment on this 

approach. It should also be noted that we are proposing that 

under the proposed mass-based approach, if RE located in a massbased 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 treatment of leakage and of 

interstate effects under both the proposed rate-based federal 

plan approach and the proposed mass-based federal plan approach, 

and as part of the corresponding proposed model rules. 
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3. Provisions to Encourage Early Action 

The EPA outlined and initiated the Clean Energy Incentive 

Program (CEIP) in the final emission guidelines (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 

EE projects that benefit low-income communities. These projects 

must commence construction after the date of submission of a 

complete state plan, or the effective date of a federal plan, and 

will receive incentives for the MWh they generate or the end-use 

energy demand reductions they achieve during 2020 and 2021. The 

CEIP also provides an additional incentive to drive investment in 

demand-side EE projects that benefit 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 massbased federal plans are detailed in sections IV and V of this 

preamble, respectively. 

B. Inventory of Emissions 

Fossil fuel-fired electric utility generating units (EGUs) 

are by far the largest emitters of GHGs among stationary sources 

in the U.S., primarily in the form of CO2, and among fossil fuelfired EGUs, coal-fired units are by far the largest emitters. 
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This section describes the amounts of these emissions and places 

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

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

The EPA implements a separate program under 40 CFR part 98 

called the Greenhouse Gas Reporting Program20 (GHGRP) that requires 

emitting facilities over threshold amounts of GHGs to report their 

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

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

 

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

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

Protection Agency, April 15, 2015. 

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

html

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

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

21 Sinks are a physical unit or process that stores GHGs, such as 
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emissions, for the years 1990, 2005, and 2013. 

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)

 

forests or underground or deep sea reservoirs of carbon dioxide. 

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

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

Environmental Protection Agency, April 15, 2015. 

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

html 

23 The energy sector includes all greenhouse gases resulting from 

stationary and mobile energy activities, including fuel combustion 

and fugitive fuel emissions. 
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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 of this preamble 

presents total CO2 emissions from fossil fuel-fired 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

 

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. 

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

which represents comprehensive total U.S. greenhouse gas 

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. 

GHG EMISSIONS 1990 2005 2013 

Total CO2 from fossil fuelfired EGUs  

1,820.8 

 

2,400.9 

 

2,039.8 

 - from coal 

 

1,547.6 

 

1,983.8

 

1,575.0

 - from natural gas 

 

175.3 

 

318.8 441.9 

 - from petroleum 

 

97.5 

 

97.9 22.4
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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 steam generating unit, IGCC, or stationary 

combustion turbine that was in operation or had commenced 

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

 

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

18, 2014. http://www.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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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 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 combined heat and power 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. 

Combined heat and power (CHP) combustion turbine means any SCT 

which recovers heat from the combustion turbine engine exhaust 

gases to heat water or another medium, generate steam for useful 
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purposes other than exclusively for additional electric 

generation, or directly uses the heat in the exhaust gases for a 

useful purpose.

We note that certain affected EGUs are exempt from 

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

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

subject to subpart TTTT as a result of commencing modification 

or reconstruction; (2) are steam generating units or IGCC units 

that are currently and always have been subject to a federally 

enforceable permit limiting net-electric sales to one-third or 

less of its potential electric output or 219,000 MWh or less on 

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

capable of combusting 50 percent or more non-fossil fuel) that 

have historically limited the use of fossil fuels to 10 percent 

or less of the annual capacity factor or are subject to a 

federally enforceable permit limiting fossil fuel use to 10 

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

stationary combustion turbines that are not capable of 

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

pipeline); (5) are a combined heat and power unit 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 
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efficiency and the potential electric output or 219,000 MWh 

(whichever is greater) or less; (6) serve a generator along with 

other steam generating unit(s), IGCC(s), or stationary 

combustion turbine(s) where the effective generation capacity 

(determined based on a prorated output of the base load rating 

of each steam generating unit, IGCC, or stationary combustion 

turbine) is 25 MW or less; (7) are a municipal waste combustor 

unit subject to subpart Eb of 40 CFR part 60; or (8) are a 

commercial or industrial solid waste incineration unit that is 

subject to subpart CCCC of 40 CFR part 60.29

The EPA is requesting comment on whether it may be 

appropriate to include a conditional exemption for certain 

small- and medium-sized steam EGUs that are willing to commit to 

 

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 Emission Guidelines that states 

need not include certain units that would otherwise meet the CAA 

section 111(b) applicability in this CAA section 111(d) emission 

guidelines. These include simple cycle turbines, certain nonfossil units, and certain combined heat and power 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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decommissioning within a fixed time period prior to 2030. The 

agency is interested in what the size threshold for such an 

exemption might be (e.g., 100 MW nameplate capacity or less), 

its effect on emissions performance under a federal plan, and 

whether a particular date corresponding with the timing of the 

compliance periods (e.g., the end of the first compliance period 

on December 31, 2025) would be appropriate in order to ensure 

overall benefits in performance are obtained from the use of the 

conditional exemption.

The applicability of this proposed federal plan follows the 

same applicability criteria as the final EGs. The rationale for 

these criteria is provided at &&&citation to EGs. We are not 

reopening the criteria or rationale here. 

In the federal plan Affected EGU 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 Clean Power Plan. 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. 

Commented [A1]: Please clarify 

whether this would require 

emission neutrality 
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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 

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 
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federal plan or other action.30

The EPA recognizes that the compliance periods provided for 

in this rulemaking are longer than those historically and 

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

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

generally not exceed one month.” See e.g., June 13, 1989 

Guidance on Limiting Potential to Emit in New Source Permitting 

and January 25, 1995 Guidance on Enforceability Requirements for 

Limiting Potential to Emit through SIP and §112 Rules and 

General Permits. The EPA determined that the longer compliance 

periods provided for in this rulemaking are acceptable in the 

context of this specific rulemaking because of the unique 

characteristics of this rulemaking, including that CO2 is longlived in the atmosphere, and this rulemaking is focused on 

performance standards related to those long-term impacts. 

• Prior to the beginning of the first compliance period in 

2022, the agency intends to establish the infrastructure for 

operating a federal trading program and to work closely with 

affected EGUs in the states where the federal plan is 

 

30 This schedule would be the same under either a rate- or massbased approach. 
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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 emission guidelines and a federal plan that 

implements a trading system. 

The EPA recognizes that it is important to ensure a degree 

of liquidity in compliance instruments in either of the 

proposed trading approaches, while also maintaining the 

stringency required by the final EGs. A number of aspects of 

the rate-based and mass-based programs would assist with 

this, including through 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, 
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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 

section to the Federal Power Act to make reliability standards 

mandatory and enforceable by 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, DOE, state PUCs, 

 

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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ISOs/RTOs, and other planning authorities also consider the 

reliability of the electric system. There are also numerous 

remedies that are routinely employed when there is a specific 

local or regional reliability issue. These include transmission 

system upgrades, installation of new generating capacity, 

calling on demand response, and other demand-side actions. 

Additionally, planning authorities and system operators 

constantly consider, plan for, and monitor the reliability of 

the electricity system with both a long-term and short-term 

perspective. Over the last century, the electric industry’s 

efforts regarding electric system reliability have become 

multidimensional, comprehensive, and sophisticated. Under this 

approach, planning authorities plan the system to assure the 

availability of sufficient generation, transmission, and 

distribution capacity to meet system needs in a way that 

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

planning happens at both the local and regional levels with all 

segments of the electric system needing to operate together in 

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

 

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

An Overview of the Technology, the Marketplace, and Government 

Regulations, IEEE Press, at 160 (2010).
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system operators operate the system within safe operating 

margins and work to restore the system quickly if a disruption 

occurs.33 Mandatory reliability standards apply to how the bulk 

electric system is planned and operated. For example, 

transmission operators and balancing authorities have to 

develop, maintain, and implement a set of plans to mitigate 

operating emergencies.34 

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

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

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

interfere with the industry’s ability to maintain reliability of 

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

the EG, provides more than 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 

 

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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proposed federal plan includes two alternative approaches; a 

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

Trading programs of both types have many positive attributes. 

Among them is that they help to ensure that imposition of the 

federal plan will not interfere with the industry’s ability to 

maintain the reliability of the nation’s electricity supply. 

Such a program does not restrict unit-level operational 

decision-making beyond requiring units to hold a sufficient 

number of tradable permits (e.g., allowances or ERCs) to cover 

emissions. It therefore inherently allows for unit level 

operational flexibility to facilitate the maintenance of 

reliability and makes the program enormously resilient. If a 

unit finds it needs to run more than anticipated, the marketbased compliance system provides a way for the EGU to meet its 

generation needs while it maintains compliance with the federal 

plan. 

Third, just as we have required the states to do in

developing state plans, the EPA is considering reliability as a 

part of developing this federal plan. For example, the EPA will 

consult with planning authorities. The EPA will work with the 

ISO/RTO Council to convene a face-to-face meeting for planning 

authorities with the EPA during the comment period to discuss 

any concerns or other feedback on the federal plan from those 
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entities. This meeting will help to ensure that the EPA is 

taking into consideration any concerns about the relationship of 

this rulemaking to the ability of the industry to maintain 

electric reliability across the country as we finalize the 

federal plan. It will give the planning authorities an 

opportunity to hear directly from the EPA how the federal plan 

is designed and gives the planning authorities an opportunity to 

voice concerns and ask questions. This will help inform comments 

that planning authorities may submit to the docket. 

In the final Clean Power Plan EGs, the EPA laid out the 

availability of a reliability safety valve that could be used if 

an unanticipated catastrophic emergency caused a conflict 

between maintenance of electric reliability and inflexible 

requirements that a state plan might impose on an affected EGU 

or EGUs. Under the federal plan, inflexible requirements are not 

imposed on specific plants. Rather as explained earlier, the 

very nature of the federal plan, in which affected EGUs can 

obtain allowances or credits if needed, supports reliability. 

Therefore, a reliability safety valve for the federal plan is 

not needed. The EPA invites comments on this aspect of the 

proposed federal plan. 

The EPA, DOE and FERC have agreed to coordinate efforts to 

help ensure continued reliable electricity generation and 
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transmission during the implementation of the final EG and the 

final federal plan in any state that does not have an approved 

state plan. The three agencies have developed a coordination 

strategy that reflects their joint understanding of how they 

will work together to monitor implementation. The three agencies 

will work together to monitor implementation, share information 

and resolve any difficulties that may be encountered. 

The EPA is not proposing to include an allowance set-aside, 

or similar mechanism in a rate-based approach, to address 

reliability issues in the federal plan; however, we request comment 

on including such a set-aside in the context of a mass-based 

approach. The EPA requests comment specifically on creation of an 

allowance set-aside for the purpose of making allowances available 

in emergency circumstances in which an affected EGU was compelled 

to provide reliability critical generation and demonstrated that 

a supply of allowance needed to offset its emissions was not 

available. 

The set-aside would be in addition to the proposed set-asides 

that are detailed in section V.D in this preamble. The EPA would 

set aside allowances in each state under the mass-based federal 

plan, and if a reliability issue is perceived by the EPA, DOE, and 

FERC coordinated monitoring process discussed above, the EPA would 

distribute allowances from the set-aside to support affected EGUs 
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during or after an unforeseen, emergency reliability event. If 

there were unused allowances remaining in the set-aside then the 

EPA would distribute them to affected EGUs pro rata based on the 

allocation approach that is detailed in section V.D of this 

preamble. The EPA requests comment on all elements of such an 

approach, including what events would trigger the need for 

allowances from the reliability set-aside; eligibility criteria to 

receive the set-aside allowances; the size of the set-aside; and 

the timing of distribution of allowances from the reliability setaside. Additionally, the EPA requests comment on how a reliability 

“set-aside” approach could be implemented in the rate-based 

federal plan. 

As detailed later in this preamble, the EPA proposes in the 

federal plan to implement a Clean Energy Incentive Program, 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 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 
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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. 

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 
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paragraph, the Administrator shall take into consideration, 

among other factors, remaining useful lives of the sources in 

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

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

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

we explained how the Guidelines permit states in applying a 

standard of performance in their state plans to consider the 

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

appropriate to specify that the general variance provisions in 

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

facilities covered by these Guidelines. &&&citation. We 

concluded that facility-specific factors and in particular, 

remaining useful life, do not justify a state making further 

adjustments to the performance rates or aggregate emission goal 

that the Guidelines define for affected EGUs in a state and that 

must be achieved by the state plan. 

Because the Guidelines do not allow for states to deviate 

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

not believe such goal adjustments are necessary or appropriate 

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

the requirement that the EPA itself, in the design of its 

federal plan, consider, among other factors, the remaining 

useful lives of the affected facilities. The agency therefore 
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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 

 

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. &&&citation. We believe that analysis demonstrates 

that this is not likely to be a widespread issue under the federal 

plan either. 
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cease operation if the only means of emission limitation 

available to meet emission limits were pollution control 

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

This language is probative of the fact that Congress viewed 

“remaining useful lives” as a consideration for facilities with 

relatively little remaining useful life. We are confident the 

proposed federal plan will not force costly pollution control 

investments at older plants with short remaining useful lives. 

Further, the statute provides that this factor is one 

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

promulgating a standard of performance. Congress provided no 

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

The inclusion of unspecified factors that the agency may 

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

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

a substantial degree of discretion in determining how the 

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

not require, and Congress did not intend, that this

consideration mandate the agency to prevent all premature 

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 
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time of the 1977 Amendments. For example, Congress excluded 

plants in existence before August 7, 1977 from the 

preconstruction requirements of the PSD/non-attainment new 

source review 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 
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useful life will clearly exceed th[e] time period [for 

amortization based on the type of control], the remaining 

useful life has essentially no effect on control costs and 

on the BART determination process. Where the remaining 

useful life is less than the time period for amortizing 

costs, you should use this shorter time period in your cost 

calculation. 

40 CFR part 51, 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 first years of the program. These tools will 
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create economic incentives that reward over-performance of some 

affected EGUs, and allow others to simply acquire credits or 

allowances to comply with their emission standard, thereby 

avoiding the need for installation of costly pollution controls 

at sources with a short remaining life. 

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

that it adequately, and inherently, takes into account the 

remaining useful lives of affected EGUs. It provides substantial 

compliance flexibility, including means of avoiding the need to 

make extensive capital investments in control technologies that 

could not be recouped during the remaining useful lives of a 

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

 

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

through the basic design of the federal plan, we also can confirm, 

in line with the Emission Guidelines, that the availability of 

variances from the emission standards is unnecessary in the federal 

plan. Under the general framework regulations, facility-specific 

variances from an otherwise applicable standard of performance 

have been potentially available under the application process in 

40 CFR 60.27(e)(2), which incorporates the factors provided in 40 

CFR 60.24(f) for states. Consistent with our view that the federal 

plan adequately considers remaining useful lives, and for the same 

reasons, the need for facility-specific variances under the 

circumstances of 60.24(f) (unreasonable costs of controls, 

physical impossibility of installation of necessary control 

equipment, or other factors that make longer compliance times or 
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trading provides individual affected EGUs the flexibility to 

make cost-conscious compliance choices. This flexibility avoids 

or substantially diminishes any likelihood that compliance will 

be a physical impossibility or result in unreasonable costs. 

By relying on either rate- or mass-based emission trading, 

the proposed federal plan capitalizes on the inherent 

flexibility available through market-based techniques. In 

effect, under a trading program with repeating compliance 

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

total outlay that is proportionately smaller than a facility 

with a long remaining useful life, simply because the first 

facility would need to comply for fewer compliance periods and 

would need proportionately fewer ERCs or allowances than the 

second facility. Buying ERCs or allowances as a compliance 

method could avoid excessive up-front capital expenditures that 

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 

 

less stringent standards significantly more reasonable) are 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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immediate costs of compliance, particularly for facilities that 

have useful lives ending before 2022, but also for facilities 

that have useful lives ending before 2030. There are no 

compliance obligations for affected EGUs under this federal plan 

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

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

the EGs, which begins with relatively higher emission targets 

that will slowly strenghten over the interim performance period 

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

final, most stringent, compliance obligation does not begin 

until 2030. 

Further, unlike state plans that can be more stringent 

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

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

reflect a reasonable, rather than a maximum possible, 

implementation level for each building block in order to 

establish overall goals that are achievable. As discussed in the 

EG, &&&cite, the BSER determined an average level of emissions 

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 
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essence, it allows the facilities to comply with the federal 

plan through the purchase or acquisition of ERCs or allowances, 

and to avoid the need to make costly investments in control 

technology for plants that have short remaining useful lives.37

For these reasons, we believe the federal plan adequately 

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

consideration of facilities’ “remaining useful lives” in the 

federal plan. 

H. Implications for Other EPA Programs and Rules 

1. Title V Permitting 

a. Permitting Requirements 

Under the proposed federal plan, title V permits for 

sources with affected EGUs will need to include any new 

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 

 

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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CFR parts 70 and 71.38 All major stationary sources of air 

pollution and certain other sources are required to apply for 

title V operating permits that include emission limitations and 

other conditions as necessary to assure compliance with 

applicable requirements of the CAA, including the requirements 

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

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

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

permits are defined in the title V regulations, and include 

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

(definition of “applicable requirement”)). 

The EPA anticipates that, given the nature of the units 

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

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

permitting requirements. For sources subject to title V, the 

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 

 

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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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 

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 
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has the potential to emit greenhouse gases 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. 

The title V permits program is structured to provide 

flexibility for market-based approaches, such as allowance 

 

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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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 

modification procedures for permit modifications “involving the 
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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 
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the final Cross-State Air Pollution Rule (CSAPR). See 76 FR 

48299-30 (Aug. 8, 2011). The agency recently issued guidance to 

assist permitting authorities and sources subject to CSAPR in 

incorporating CSAPR requirements into title V permits.40 The EPA 

invites comment on its proposed approach to permitting 

requirements for the federal plan, including whether it would be 

of use to develop guidance similar to the guidance developed for 

permitting under CSAPR. The EPA invites comment on its proposed 

approach to incorporating applicable requirements of the federal 

plan into title V permits and revising those requirements, 

including specifically seeking comment on whether all 

requirements should be eligible for incorporation into title V 

permits via minor modification procedures or if only a specified 

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. 

 

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

Division, OAQPS, and Reid P. Harvey, Director, Clean Air Markets 

Division, 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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2. Implications for New Source Review Program 

 The new source review (NSR) program is a preconstruction 

permitting program that requires major stationary sources of air 

pollution to obtain permits prior to beginning construction. The 

requirements of the NSR program apply both to new construction 

and to modifications of existing major sources. Generally, a 

source triggers these permitting requirements as a result of a 

modification when it undertakes a physical or operational change 

that results in a significant emission increase and a net 

emissions increase. NSR regulations define what constitutes a 

significant net emissions increase, and the concept is 

pollutant-specific. 

In the final EGs, &&&[citation], the EPA recognized that, 

as part of its CAA section 111(d) plan, a state may impose 

requirements that require an affected EGU to undertake a 

physical or operational change to improve the unit’s efficiency 

that results in an increase in the unit’s dispatch and an 

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 
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be few. 

The EPA believes the analysis of NSR applicability is 

basically the same for sources under a CAA section 111(d) 

federal plan. That is, it is conceivable that a source under a 

federal plan may choose, as a means of compliance with either a 

rate-based or mass-based approach, to undertake a physical or 

operational change to improve an affected EGU’s efficiency that 

results in a significant net emissions increase of a regulated 

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

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

After the proposal for the Clean Power Plan was published 

in June of 2014, the United States Supreme Court issued its 

opinion in UARG v EPA, 134 S. Ct. 2427 (June 23, 2014). The 

Supreme Court held that an increase in greenhouse gas emissions 

alone cannot by law trigger the NSR requirements of the PSD 

program under section 165 of the CAA. On remand from the Court, 

the D.C. Circuit issued an amended judgment in Coalition for 

Responsible Regulation, Inc. v. Environmental Protection Agency, 

Nos. 09-1322, 10-073, 10-1092 and 10-1167 (D.C. Cir., April 10, 

2015), vacating the relevant regulations. Therefore, increases 

in emissions of greenhouse gases 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 
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increases its operations due to generation shift from a steam 

generating unit), 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 

harmonizing or streamlining the permitting process for such 

sources that are consistent with judicial precedent. However, 

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

action, and the agency is not reopening or reconsidering any 

prior actions or determinations related to NSR in this action. 

Any comments related solely to the NSR program will be 

considered out of 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 EPA41. 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 

(CCR Rule), issued on December 19, 2014; and the proposed Steam 

 

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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Electric Effluent Limitation Guidelines and Standards (SE ELG 

Rule) (78 FR 34432; June 7, 2013). These rules are discussed in 

more detail in the final EGs along with steps the EPA is taking 

to enable compliance with obligations under other power sector 

rules as efficiently as possible. &&&citation. We solicit 

comment on whether there are specific things the EPA can do in 

the design and implementation of the federal plan that further 

this objective. 

I. Administrative Appeals Process 

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

the EPA anticipates that there may be situations in which 

individual parties are affected by decisions of the agency. For 

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

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

part 78 to accommodate such appeals. The part 78 procedures 

cover prior CAA emission trading programs and were specifically 

designed with these types of disputes in mind. 

The persons eligible to file such appeals would be similar 

to the existing definition of an “interested person” in part 78. 

The filing of an appeal and the exhaustion of administrative 

remedies under part 78 would be a prerequisite to seeking 

judicial review. For purposes of judicial review, final agency 

action would occur only when an agency decision under the 

federal plan listed as appealable under part 78 has been issued, 

and the procedures of part 78 for appealing the decision are 

exhausted. 

The actions we propose to list as appealable under the part 

78 procedures are as follows. 

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 affecte EGUs’ 

compliance accounts; decisions on the accreditation of 
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independent verifiers; the use of error corrections regarding 

information submitted by ERC providers, affected EGUs, or other 

ERC account holders; and the finalization of control period 

emissions data, including retroactive adjustment based on audit 

or other investigation. 

In the case of a mass-based federal plan: decisions on an 

eligibilty application for set-aside allowances; decisions 

regarding the allocation of allowances to affected EGUs; 

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

regarding the finalization of emissions data by affected EGUs 

during compliance periods; decisions making error corrections to 

information submitted by affected EGUs and other account 

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 
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finalize an administrative appeals process that differs in any 

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

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

aspects of the alternative or additional adminsitrative appeals 

process, including with respect to any structural, procedural, 

subtantive, and timing requirements it should include, who 

should have access to it and in what manner, and how it would 

differ from part 78. Finally, we request comment on whether, 

similar to other programs identified in 40 CFR 78.1(a)(1), the 

agency should make the procedures of part 78 available to any 

actions of the Administrator under the comparable state 

regulations approved as a part of a state plan under the EGs. 

J. Consistency of Program Structure with Clean Air Act Authority 

The EPA is co-proposing two distinct forms of emissions 

trading as the mechanism for federal implementation of standards 

of performance that achieve the emission performance levels by 

determined by application of the Best System of Emission 

Reduction (BSER) in the Clean Power Plan EGs. Both proposals are 

“emission standard” approaches as defined in the EGs, and the 

EPA is not proposing an approach like the “state measures” 

approach that is also available to states in the final EGs. The 

EPA has legal authority to establish either of the proposed 

trading systems as a federal plan under CAA section 111(d)(2). 
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We discuss this topic briefly here and invite public comment. 

The EGs discussed the role of emissions trading in the BSER, 

see, e.g., section V.A of the preamble to the final EGs. The EPA 

regards this to be a separate issue and is not revisiting or 

reopening the discussion of the BSER or the role of trading in 

the BSER here. The EGs recognize and provide ample opportunity 

for states to establish standards of performance that allow the 

use of emissions trading or other multi-unit compliance 

approaches. Here we discuss why an emissions trading program is 

a lawful and appropriate form of federal “implementation” of a 

“standard of performance” under CAA section 111(d)(2). We invite 

comment on this legal discussion and the agency’s 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 
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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 NAAQS 

pollutants under CAA section 110. This authority under CAA 

section 111, of course, must be understood in reference to the 

purpose of that section (i.e., to achieve emission reductions 

for designated pollutants from designated facilities), rather 

than in reference to the purpose of section 110 (i.e., to attain 

and maintain the NAAQS). However, it has been the agency’s 

longstanding view that, in both procedural and substantive 

respects, Congress intended that the CAA section 110 authority 

be looked to under CAA section 111(d)(2). See 40 FR 53340, at 

53342 (Nov. 17, 1975) (“It is obvious that [the Administrator] 

 

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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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 state 

implementation plan. Thus, in promulgating a FIP under CAA 

section 110, the EPA may exercise its own, independent 

regulatory authority in accordance with CAA section 110(c) and 

the CAA more broadly. When the EPA has promulgated a FIP, courts 

have not required explicit authority for specific measures: “We 

are inclined to construe Congress’ 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
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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 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 
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a state to the EPA’s predicate action on a state implementation 

plan (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 the case law.44 The scope of the 

EPA’s action to undertake a FIP under CAA section 110 is 

informed by the scope of the state’s action to undertake a SIP; 

likewise, the scope of the EPA’s action to undertake a federal 

 

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

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

discussed in section VII of this preamble, below, the current 

version of CAA section 110, including subsection (c), reflects 

changes made in the 1990 Amendments based on experience gained in 

the first two decades of the CAA’s implementation. The statute and 

legislative history do not expressly address the question, but 

there is no indication Congress would have intended to prevent 

these improvements from being available under CAA section 111 as 

well. 
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plan under CAA section 111(d) is informed by the scope of the 

state’s action to undertake a state plan. 

The agency received comments on the proposed EGs from 

commenters who stated that the EPA cannot require states to 

implement the building blocks that make up the BSER, for example, 

ordering re-dispatch to natural gas-fired units, or ordering the 

construction of renewable energy 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 federalplan state, provide mechanisms for their implementation and 

enforcement, and otherwise leave to the owners and operators of 

the affected EGUs the decisions about what measures they want to 

take to comply with the emission standard. Though the emission 

standards will be federally enforceable, as under a state plan, 
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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 renewable energy 

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 
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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 Emissions Guidelines. See 

section V.A of the final EGs. Here we supplement that discussion 

with respect to the agency’s own authority under CAA section 

111(d)(2) to use trading as a method of implementation of a 

“standard of performance” in the federal plan. 

The 1990 CAA Amendments added broad authorizations for the 

use of market techniques in several sections of the statute, 

including in Title I. States were provided express authority to 

use such approaches in their NAAQS implementation plans under 

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

enforceable emission limitations and other control measures, 

means, or techniques (including economic incentives such as 

fees, marketable permits, and auctions of emissions rights)....” 

42 USC 7410(a)(2)(A). The EPA was given similar authority in the 
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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). 

Case law throughout the history of the CAA has generally 

confirmed the legal viability of emissions trading as an 
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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,” 

finding in that term sufficient ambiguity to support the 
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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 

 

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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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 

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 

 

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

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

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

tradable allowances. The statute authorized the EPA to issue 

regulations “for the control of any substance, practice, 

process, or activity (or any combination thereof) which in his 

judgment may reasonably be anticipated to affect the 

stratosphere, especially ozone in the stratosphere, if such 

effect in the stratosphere may reasonably be anticipated to 

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
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affirmatively prohibiting market incentives would be, in the 

OLC’s words, to read into the statute the italicized clause 

“regulations for the control [of CFCs] by traditional command 

and control or specification standard methods,” id. At 9 – a 

rewriting “unwarranted in any case, but especially so where 

Congress was aware of economic methods of control and where such 

methods so ably serve the underlying purposes of the statute.” 

Id.

By the time of the 1990 CAA Amendments, as discussed above, 

Congress was comfortable enough with the efficacy of market 

techniques that they were broadly authorized for use in state 

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 

 

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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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), 

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, 

&&&cite&&&, the EPA has instituted or authorized the use of 

emissions trading programs twice in the past under CAA section 

111(d). The EPA authorized NOx emissions averaging or trading 

within or between facilities under the Municipal Waste 

Combustors Emission Guidelines 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 

 

48 The EPA notes that complications that arise with respect to 

assigning a “significant contribution” among upwind states for 

NAAQS pollutant levels in downwind states, and designing a trading 

regime that accomplishes Good Neighbor objectives, are not present 

with respect to CO2, which is a global pollutant; emission 

reductions anywhere contribute to the environmental objective of 

addressing climate change. 
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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 

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 

 

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 pollutant (HAP). No 

such procedural concern is present here with respect to CO2, which 

is not a HAP under CAA section 112. 

50 We recognize that some commenters on the EGs raised concerns 

about the localized impacts that may occur from the potential for 

concentrations of co-pollutants associated with CO2emitted from 
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Finally, the Supreme Court has affirmed the breadth of the 

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

method by which it would control 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 greenhouse gas-producing sector 

cannot be prescribed in a vacuum: as with other questions of 

national or international policy, informed assessment of 

competing interests is required. Along with the environmental 

benefit potentially achievable, our Nation’s energy needs and 

the possibility of economic disruption must weigh in the 

balance. The 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 

 

affected EGUs. We address those concerns in the communities 

sections of the final EGs, at &&§ion, and in this preamble in 

&&§ion IX below. 
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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 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 
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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.3.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 emission guidelines. For the 

federal plan, the EPA is proposing to limit the issuance of ERCs 

to designated categories of affected EGUs and to renewable 

energy 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 emission guidelines. 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-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, M&V 

report, and verification report requirements should apply for 

each eligible resource. Further discussion of non-BSER measures 
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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 steam 

generating units (i.e., utility boilers and IGCC units)51. The 

CO2 emission performance 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 steam generating 

units, respectively. For a thorough discussion of affected EGU 

 

51 For simplicity, affected utility boilers and IGCC units will 

collectively be called “steam generating units.” 
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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. 

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 
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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 

Steam generating 

unit or integrated 

gasification 

combined cycle 

(IGCC) 

1,671 1,500 1,380 1,305 

Stationary 

combustion turbine 

877 817 784 771 

The EPA is using the subcategorized rates in the rate-based 

trading approach because it allows ERCs to be fungible across 

jurisdictional borders and provides an incentive structure, as 

compared to other rate-based approaches, that facilitates 

implementation of measures identified as part of the BSER. Using 

subcategorized rates allows for: (1) A relatively equitable 

distribution of burden for emission reductions aross the 
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sector52; 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 trading rule.53 If a 

subcategorized approach for a rate-based model rule and federal 

plan is not preferred by commenters, the EPA requests comment on 

the perceived benefits of an alternative rate or set of rates 

(e.g., applying a uniform rate, i.e., the state goal, to all 

affected units within the state as the EGUs’ emission standard). 

C. Crediting Mechanism 

Under a rate-based emission standard 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 

 

52 This is compared to a single rate that applies to all facilities 

and is, in most cases, anticipated to impart more burden on steam 

generating units because they will be subject to a comparatively 

lower standard. 

53 Note that the values of limits and determinations made as the 

BSER are not open for comment. 
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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; 

(2) affected NGCC units for all generation (represents shifting 

generation from steam generating units 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 crediting mechanism to meet 

compliance obligations is consistent with the CPP EGs and is 
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being adopted in this federal plan54. 

Because the goal of this rulemaking is the actual reduction 

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

of energy generation or savings they purport to represent. To 

this end, only valid ERCs that actually meet the standards 

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

compliance by an affected EGU with emission standards. The 

responsibility for the validity of the ERC rests with the 

affected EGU. Despite safeguards included in the structure of 

ERC issuance and tracking systems, such as the review of 

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

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

eligible zero-emission MWh as required in the emission 

guidelines. 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 

 

54 The use of ERCs and definition as a compliance mechanism to meet 

the BSER emission performance rates is established in section 

IV.A.5.a of the final EGs. [&&&] 
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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 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 
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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 

implementation of a federal plan and a model trading rule, and 

we take comment on any alternatives to this approach that still 

fall within the established criteria described in the CPP EGs. 

Comments that solely relate to determinations finalized in the 

EGs will be considered out of scope. 

2. Incremental NGCC ERCs 

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

EGs describes shifting generation from steam generating units to 

NGCC units because NGCC units generate electricity at a less 
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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.55 The EPA is proposing to reflect 

the emission reductions of BB2 by crediting all NGCC generation 

on a pro-rata basis that reflects expected incremental NGCC 

generation to 75 percent capacity. This means that for every 

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

partial credit associated with the generation shift from fossil 

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

because the emission reductions associated with BB2 have been 

distributed on an hourly basis. A discussion on the concepts 

behind the distribution of emission reductions of incremental 

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

this subsection. 

All affected NGCC generation will be credited, with ERCs, 

by a factor that represents the described emission reductions 

 

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

levels is displacing fossil fuel-fired steam EGU generation. 
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from incremental generation; ERCs credited in this way will be 

designated as Gas Shift ERCs (GS-ERCs) for clarity56. 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 

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 reductionsanticipated under BB2 

 

56 A GS-ERC is treated and represents the same value as an ERC, but 

has a compliance restriction that it can only be used by steam 

generating units and not by stationary combustion turbines for 

compliance obligations. 
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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 steam generating unit 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 region57 (i.e., the region with the 

highest calculated emission rate standard for steam generating 

units). The GS-ERC Emission Factor is expressed by taking the 

complement of the ratio of the NGCC standard to the fossil-steam 

standard. It can be summarized by the following expression: 

GS-ERC	Emission	Factor	 = 1 − 	

NGCC	emission	rate	

Steam	Standard

The second factor is the Incremental Generation Factor. 

 

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

are the Eastern Interconnect, Western Interconnect, and Electric 

Reliability Council of Texas (ERCOT). 
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This factor represents the distribution of the increased NGCC 

generation across the all NGCC generation. In essence, it is 

prorating the incremental NGCC generation over all NGCC 

generation. The Incremental Generation Factor is calculated by 

taking the number of MWh beyond the 2012 baseline needed for the 

corresponding region to reach 75 percent NGCC generation 

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

generation capacity, giving a factor. This factor can be 

summarized by the following expression: 

Incremental	Generation	Factor = 	1 −

Regional	2012	NGCC	Baseline	

75	%	NGCC	Regional	Capacity	

The Incremental Generation Factor is a factor that the EPA will 

calculate and will be calculated for every compliance period 

based on the least stingent region’s Incremental Generation 

Factor based on increased utilization of RE and its replacement 

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

the CPP EGs).58 For the calculation of this factor the EPA is 

using the least stringent region for each compliance period and 

 

58 Note that per the discussion in section VI of the final EGs, 

if the EPA had measured incremental NGCC generation for 

reassignment to fossil steam rate as the difference from the 

post building block three levels and full utilization, the post 

building block three levels would be used in the numerator here, 

resulting in a higher “incremental generation factor” and more 

ERCs for the same amount of NGCC generation. 
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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 

prorating all incremental NGCC generation and the GS-ERC 

Emission Factor designating the proportion of the incremental 
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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 Planthe BSER determination for 

subcategory rates is calculated by using the least stringent 

region and applying the standards from that region on a national 
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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 
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the final performance period. During this year it emits 850 

million lbs of CO2 giving it an emission rate of 850 lbs CO2/MWh. 

The NGCC is subject to a final period emission rate limit of 771 

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

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

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

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,

	/	.1,000,000	MWh + ERC	MWh3 	 = 	771	lbs		CO,/MWh

When that equation is solved for the number of ERC MWh needed, 

the NGCC would need to acquire 102,464 ERCs to adjust its 

emission rate to its emission rate standard. 

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

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

and 1,404 lbs CO2/MWh for the steam generating unit 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 
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TSD and is proposed to be 0.26. By using the GS-ERC Emission 

Factor and Incremental Generation Factor calculated above with 

the NGCC’s generation for the year, the number of GS-ERCs for 

this NGCC can be calculated. 

0.45 ∗ 0.26 ∗ 1,000,000 = GS-ERC

The calculation results in 117 thousand GS-ERCs being generated. 

Because an NGCC cannot use the GS-ERCs it generates to meet its 

compliance obligations, this NGCC will both generate ERCs 

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

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

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

used to acquire non-GS-ERCs to satisfy the NGCC’s compliance 

obligations. 

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

obligation because they are generated to reflect incremental 

NGCC generation replacing a steam generating unit’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 
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considering this methodology that GS-ERCs are generated for all 

NGCC generation because it ensures that all existing NGCC units 

are encouraged to run at a greater capacity. The EPA is 

requesting comment on alternative methods to account for NGCC 

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

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

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 a 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 
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shift from fossil steam to NGCC units by the NGCC operating rate 

being evaluated against the fossil steam standard. For all 

incremental NGCC generation the NGCC operating rate is compared 

against two different standards: (1) The NGCC standard against 

which ERC generation is evaluated; and (2) the steam standard 

against which GS-ERC generation is evaluated. An evaluation 

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 
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determinations finalized in the EGs will be considered out of 

scope. 

3. Eligible Emission Reduction Measures for ERC Generation 

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

specify emission reductions measures used to adjust an emission 

rate that are eligible for ERC issuance under the federal plan. 

Specifically, the EPA is proposing that RE generation that meets 

the requirements for eligible resources in the emission 

guidelines, all other requirements related to ERC issuance in 

the emission guidelines 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: 

on-shore wind, solar photovoltaics (PV), concentrated solar 

power, geothermal power, and hydropower.59 Further, the EPA is 

proposing that new nuclear units and capacity uprates at 

 

59 This treatment for RE as an eligible measure type is also 

proposed for the set-aside for RE that is part of the proposed 

mass-based implementation approach co-proposed in section V of 

this preamble as the federal plan, and all proposed aspects of the 

eligible measure types described in this section and the requests 

for comment included below also apply in the mass-based set-aside 

context. Incremental nuclear is not eligible for the RE set-aside. 

The set-aside method and the use of this eligibility treatment 

within it are specified in section &&& of this preamble. 
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existing nuclear units that meet the requirements for eligible 

resources in the emission guidelines (as specified in section 

VIII.K of the final EGs) and all other requirements related to 

ERC issuance in the emission guidelines 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 and section IV.G.4 of this preamble. 

The EPA is proposing the inclusion of these measure types 

for the following reasons. These technologies, with the 

exception of nuclear, are part of the quantification of 

renewable energy 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 

guidelines for details on the treatment of these measures in 

BSER (see section V.E of this preamble). 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, as they can use their existing metering 

infrastructure to quantify generation and submit it for ERC 
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issuance. A unique concern 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 

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 (see below). 

The EPA requests comment on the inclusion of various types 

of demand-side EE as eligible measures, 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 
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inclusion of combined heat and power (CHP) as an eligible 

measure. 

The EPA requests comment on the inclusion of any other 

emission reduction measures beyond those mentioned here, as long 

as they meet the eligibility requirements outlined in the final 

EGs for rate-based crediting. For all of the above measures on 

which the EPA requests comment, the agency is particularly 

interested in comments on how EM&V methods can be implemented 

for these measures across applicable jurisdictions in the 

timeframe provided by this proposal in a way that is rigorous, 

straightforward, widely demonstrated, and in accordance with the 

EM&V requirements in this proposal, outlined in 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. The agency is requesting comment on 

appropriate processes through which the EPA and/or stakeholders 

could make a demonstration of the appropriateness of new measure 
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types and the EPA could evaluate and approve the demonstration 

so that a new measure type can be considered eligible for ERC 

issuance under the federal plan. 

 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 I.2.c of the final EGs). The use of some kinds of 

biomass has the potential to offer a wide range of environmental 

benefits, including carbon benefits. However these benefits can 

typically only be realized 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.60

 

60 Types of waste-derived biogenic feedstocks may include: landfill 

gas generated through the decomposition of 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 
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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 renewable energy incentives 

and standards, and GHG accounting procedures.61 

In addition to acknowledging such state programs, the EPA 

has undertaken a technical assessment of biogenic CO2 emissions 

from stationary sources associated with the production, 

processing and use of biomass fuels. In November 2014, the 

agency released a second draft of the technical report, 

Framework for Assessing Biogenic Carbon Dioxide for Stationary 

 

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). 

61 Some states, for example Oregon and California, have programs 

that recognize the multiple benefits that forests provide, 

including biodiversity and ecosystem services protection as well 

as climate change mitigation through carbon storage. Others, like 

California’s Forest Practice Regulations, support sustained 

production of high-quality timber while considering ecological, 

economic and social values. Several states focus on sustainable 

bioenergy, as seen with the sustainability requirements for 

eligible biomass in the Massachusetts RPS, which, among other 

requirements, limits old growth forest harvests. 
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Sources. The revised Framework, and the EPA’s Science Advisory 

Board (SAB) peer review of the 2011 Draft Framework, finds 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.62 The EPA is engaging in a second round of 

targeted peer review on the revised Framework with the SAB in 

2015.63 Information in the revised Framework and the second SAB 

peer review process, including stakeholder comments, will assist 

the EPA in assessing potential qualified biomass feedstocks in 

federal plan applications. 

If biomass is included as an eligible measure, we are 

taking comment on an option for biomass treatment under the 

rate-based federal plan, which would also apply to eligible 

generation under the mass-based plan allowance set-aside and to 

the calculation of covered emissions for affected EGUs that are 

 

62http://www.epa.gov/climatechange/ghgemissions/biogenicemissions.html. 

63 http://www.epa.gov/sab. 
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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 

(e.g., landfill gas) and certain industrial byproduct feedstocks 

(such as 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 reduce net CO2 emissions compared to affected EGUsmeet 

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 help 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 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 agriculture-derived biomass fuels and related CO2

Formatted: Subscript

Commented [A2]: edit 
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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. 

We take broad comment on the types of qualified 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 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 take comment on 

any other requirements that should be included in the final 

model rule regarding EM&V for qualified biomass. Discussion of 

the biomass EM&V requirements in the rate-based model rule can 
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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.G.1.b 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. This is in order to provide states further 

direction through the model rule on how states may include this 

broader set of ERC-generating resources in a rate-based plan. To 

reduce confusion over the applicability of these provisions, the 

agency has added a note in the regulatory text to clarify that 

these resources, and provisions throughout the proposed subpart 

that are related to those resources, are not applicable in the 

case of a federal plan. Rather they are proposed as part of the 

model trading rule only. However, again, the agency is 

requesting comment on the inclusion of these resources in 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 
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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 

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 
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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 insure that the ERCs issued meet the requirements of 

the emission guidelines and these proposed rules. The rate-based 

federal plan and model rule borrow many concepts from other 

successful trading programs, and the agency is interested in 

receiving additional information through comments on successful 

implementation of similar programs. 

1. Designated Representatives and Alternate Designated

Representatives 

 This section establishes the procedures for certifying and 

authorizing the designated representative, and alternate 

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 
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designated representatives and alternates in prior EPAadministered trading programs. 

The designated representative would be the individual 

authorized to represent the owners and operators of each 

affected EGU in matters pertaining to the rate-based trading 

program. One alternate designated representative could be 

selected to act on behalf of, and legally bind, the designated 

representative and, thus, the owners and operators. Because the 

actions of the designated representative and alternate would 

legally bind the owners and operators, the designated 

representative and alternate would have to submit a certificate 

of representation certifying that each was selected by an 

agreement binding on all such owners and operators and was 

authorized to act on their behalf. 

The designated representative and alternate would be 

authorized upon receipt by the Administrator of the certificate 

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 
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system certifications, and allowance transfers) for an affected 

EGU would have to be submitted, signed, and certified by the 

designated representative or alternate. Further, upon receipt of 

a complete certificate of representation, the Administrator 

would establish a compliance account in the ATCS for the 

affected EGU involved. 

In order to change the designated representative or

alternate, a new certificate of representation would have to be 

received by the Administrator. A new certificate of

representation would also have to be submitted to reflect 

changes in the owners and operators of the affected EGU 

involved. However, new owners and operators would be bound by 

the existing certificate of representation even in the absence 

of such a submission. 

In addition to the flexibility provided by allowing an 

alternate to act for the designated representative (e.g., in 

circumstances where the designated representative might be 

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 rate-based trading 

program, while ensuring accountability by owners and operators 

and simplifying the administration of the proposed rate-based 

trading program. 

2. ERC Tracking and Compliance System 

The rate-based trading program rules establish the 

procedures and requirements for using and operating the 

Allowance Tracking and Compliance System (which is the 

electronic data system through which the Administrator would 

handle ERC issuance, holding, transfer, and deduction), and for 

determining compliance with the ERC-holding requirements in an 

efficient and transparent manner. The ATCS provides a record of 

ownership, dates of ERC transfers, buyer and seller information, 

origin of ERCs, the serial numbers of ERCs transferred, and ERC 

type (i.e., if it is a GS-ERC or not). ERC price information 

would not be included in the ATCS. The EPA’s experience is that 

private parties (e.g., brokers) are in a better position to 

obtain and disseminate timely, accurate price information than 

is the EPA. For example, because not all ERC transfers are 

immediately reported to the Administrator for recordation, the 

Administrator would not be able to ensure that any reported 

price information associated with the transfers would reflect 
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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 are only used once to 

meet a regulatory obligation. This is addressed through 

specified requirements for tracking system account holders, ERC 

issuance, ERC transfers among accounts, compliance true-up for 

affected EGUs,64 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. 

 

64 “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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The EPA received a number of comments from states and 

stakeholders in the Clean Power Planabout the value of the EPA’s 

support in developing and/or administering tracking systems to 

support state administration of rate-based emission trading 

systems. As described above in section III.A of this preamble, 

the EPA is proposing, as part of both types of model trading 

rules, a federal trading platform that would allow state plans 

that are ready-for-interstate-trading to operate through a 

program in which the EPA provides the tracking and compliance 

system. This system will meet the requirements of the Clean 

Power Plan. 

4. Compliance and General Accounts 

 This section describes two types of ATCS accounts:

compliance accounts, one of which the Administrator would 

establish for each affected EGU upon receipt of the certificate 

of representation for the source; and general accounts, which 

could be established by any entity upon receipt by the 

Administrator of an application for a general account. A 

compliance account would be the account in which any ERCs used 

by the affected EGU for compliance with the emissions 

limitations would have to be held until retired for compliance. 

 General accounts could be used by any person or group for 

holding or trading ERCs. However, ERCs could not be used for 
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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 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 to be 

prescribed by the Administrator: The name and identifying 

information of the individual who would be the authorized 

account representative and of any individual who would be the 

alternate authorized account representative; an identifying name 

for the account; the names of all persons with an ownership 

interest with the respect to allowances held in the account; and 

certification language and signatures of the authorized account 

representative and alternate. The authorized account 

representative and alternate would be authorized upon receipt of 

the application by the Administrator. The provisions for 

changing the authorized account representative and alternate, 

for changing the application to take account of changes in the 

persons having an ownership interest with respect to ERCs, and 

for delegating authority to make electronic submissions would be 

analogous to those applicable to comparable matters for 

designated representatives and alternates. The EPA requests 

comment on these compliance mechanisms. 
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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.65 This averaged emission rate 

will be compared to the emissions standards that the EGU is 

subject to during the corresponding compliance period. 

Accordingly, and if necessary, the appropriate number of ERCs 

will be retired from the EGU’s compliance account to adjust the 

emission rate of the EGU to be equal to the emission standard. 

 

65 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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The discussion of using ERCs for compliance is found in section 

IV.D.8 of this preamble.

6. Recordation of ERC Generation and ERC Issuance 

The EPA proposes to issue ERCs for ERC generating entities 

once per year. Thus, in a 3-year compliance period, for 

instance, there would be three points at which the agency issues 

ERCs. After each calendar year, the EPA will calculate the ERCs 

generated for EGU and non-EGU ERC generators based on data 

submitted to the EPA through the Emissions Collection and 

Monitoring Plan System (ECMPS). These calculated ERC quantities 

will be proposed as part of a Notice of Data Availability (NODA) 

with a 30-day comment period. Subsequently, the EPA will 

finalize this NODA and issue ERCs accordingly with tracking and 

serial numbers. For affected EGUs with compliance accounts, the 

ERCs will be issued to these. For entities without compliance 

accounts, the EPA will issue ERCs to an entity’s general 

account. The timing for issuing ERCs is consistent with existing 

programs, and the EPA believes there is value in consistency. 

However, we solicit comment on the annual issuance of ERCs and 

whether issuance should occur at different intervals (e.g.,

quarterly, biannually, or other time frames). The EPA requests 

justification along with corresponding comments regarding ERCissuance intervals. We request comment on how reporting and 
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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 

rate66, 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 

streamlined and efficient federal process for ERC issuance 

across federal plan states. As required in the final EGs, we are 

 

66 As described in section IV.C.1 of this preamble. 
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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 emission guidelines: 
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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, it is proposed that

states with rate-based emission standards plans that have 

eligibility and EM&V requirements compatible with the 

federal plan will 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 take comment on whether

nuclear energy resources should be subject to the same 
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EM&V requirements as renewable energy resources, and if 

not, we take comment on to which EM&V requirements 

nuclear energy resources should be subject. 

(4) There are special conditions if the provider is 

located in a state with a mass-based plan. For eligible 

RE capacity, the provider can only be credited in a ratebased state or rzate-based multi-state system if the 

provider can demonstrate that the measure must be 

implemented to meet electricity load in a state with a 

rate-based plan. The EPA is proposing that an RE provider 

can make this demonstration by providing documentation of 

a power purchase agreement (PPA) or delivery contract 

from the rate-based state and show that the measure was 

treated as a generation resource used to serve regional load 

that included the rate-based state. For incremental nuclear 

capacity, no provider in a state with a mass-based plan 

can be eligible for ERC issuance in a rate-based state. 

This requirement and the justification for its inclusion 

is further discussed in section III.A of this preamble on 

Interstate Effects and also discussed in the Interstate 

Effects section of the final EGs (section VIII.L of the 

final EGs). The EPA is proposing that there is no other 

geographic limitation on the location of the providers of 
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RE and incremental nuclear generation under the federal 

plan. 

(5) This application must include an independent thirdparty verifier’s review and approval of the eligibility 

requirements, as is reflected in EM&V requirements for 

the final guidelines, and specified as part of proposed 

federal plan EM&V requirements in 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 
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for the public to be able to generate reports based on this 

information. 

The agency is proposing that the project eligibility 

applications will be accepted after the finalization of the 

federal plan and prior to the first compliance period, as soon 

as the agency is able to establish an application process, and 

that applications will be accepted on an annual basis. The 

agency requests comment on whether a quarterly or biannual 

application process is more appropriate. These applications 

will be accepted through the entirety of all compliance 

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: 
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(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 emission guidelines. This documentation should note 

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

a mass-based plan, and show if the generation is approved 

to be eligible for ERC issuance under the federal plan. 

See section &&& 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 
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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 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 
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ERCs may improve the EM&V process by making the eligible 

resources more accountable. 

Because it is critical to the integrity of an ERC that it 

represents the actual MWh of energy generated or saved that it 

purports to represent, and as required in the emission 

guidelines for state plans, the federal plan and model rule 

include provisions to address error correction (mechanisms to 

adjust the number of ERCs issued based on all form of errors, 

from clerical, to over- and under-statements, to material 

inconsistency with rule provisions, to fraud, etc.). In 

addition, the federal plan and model rule include provisions 

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 and substantive process at the state level to 
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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 
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period. 

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

proposes to implement the Clean Energy Incentive Program (CEIP) by 

issuing early action ERCs for eligible actions located in or 

benefitting a state that are implemented following the effective 

date of the federal plan for that state and that reduce or avoid 

CO2 emissions in 2020 and 2021. The EPA intends to implement the 

program in a way that maintains the stringency of the rate-based 

emission standards for affected EGUs in the compliance periods 

established in this rule. The EPA is proposing to award early 

action ERCs to two types of eligible projects located in or 

benefitting a state subject to the federal plan, as listed below. 

The rationale for including these projects is included in section 

VIII.B.2 of the final emission guidelines. 

• RE investments that generate metered MWh from wind or solar 

resources; and 

• Demand-side EE programs and measures that result in

quantified and verified avoided generation, and demonstrate 

a direct benefit to low-income communities. 

 The EPA proposes the following framework to implement the CEIP 

in the rate-based federal plan. First, the EPA proposes to 

implement a mechanism for issuing early action ERCs for eligible 

actions that reduce or avoid CO2 emissions in 2020 and 2021. The 
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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 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 2021. As another option, the EPA, or a state 

under the model trading rule, could use modeling to project 

expected emissions and generation for covered sources. New targets 

could then be obtained by dividing the modeled level of emissions 

by the modeled level of generation adding in the number of borrowed 

ERCs. Alternatively, future targets could be adjusted by assuming 

reference case generation and emissions over the 2022-2029 period 

and allocating those to fossil steam and NGCC using 2012 shares, 

then adding in the number of early action ERCs. The EPA requests 

comments on these ideas, as well as 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 
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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 of a federal pool of additional 

ERCs, which would be limited to the equivalent of 300 million short 

tons of CO2 emissions. The EPA proposes to distribute matching ERCs 

to all participating states based upon the amount of the reductions 

from 2012 levels each state must achieve relative to that of the 

other participating states. Thus, states under a federal plan whose 

EGUs face greater reduction obligations would 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 realized in 2020 and 2021. The number of matching ERCs 

distributed to participating states will determine the total level 

of ERCs available for provision to eligible projects in each state 

participating in the CEIP. 

The EPA proposes to execute an initial distribution of matching 

ERCs following receipt of 2016 state submittals, and a final 

distribution following receipt of all complete state plans in 2018, 

and at which time the EPA may have issued federal plans for some 

states. Eligible projects may receive awards from these matching 
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accounts upon demonstration of quantified and verified MWh of 

generation or savings achieved by eligible projects in 2020 and 

20201. The EPA requests comment on how the 300 million short ton 

CO2 emissions-equivalent pool may be converted into ERCs for the 

purpose of populating the CEIP accounts of states with rate-based 

plans. 

Third, the EPA is proposing to award early action ERCs and 

matching ERCs to eligible projects as follows, based upon the 

quantified and verified MWh of generation or savings achieved by 

the projects in 2020 and 2021: 

• For RE projects that generate metered MWh from wind or solar 

resources: for every two MWh generated, the project will receive 

one early action ERC and one matching ERC from the EPA. 

• For EE projects that benefit low-income communities: for every 

two MWh in end-use demand savings achieved, the project will 

receive two early action ERCs and two matching ERCs from the EPA. 

ERCs awarded by the EPA pursuant to the CEIP may be used for 

compliance by an affected EGU with its emission standards in any 

compliance period and are fully transferrable prior to such use. 

All matching ERCs that have not been used by January 1, 2023 would 

be retired by the EPA. 

The EPA requests comment on all aspects of implementing the CEIP 

under a rate-based federal plan approach, including (1) The method 
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for maintaining the stringency of rate-based emission standards; 

(2) the criteria for eligible projects, including criteria for 

awards to EE projects that benefit low-income communities; (3) the 

mechanism for reviewing project submittals and issuing early 

action ERCs; (4) EM&V requirements for eligible projects; (5) 

measurement and verification (M&V) reports; and (6) verification 

reports from an independent verifier. The EPA also requests comment 

on not providing matching ERCs in the rate-based trading federal 

plan. The EPA also seeks comment on how states, tribes and 

territories for whom goals have not yet been established in the 

final emission guidelines may be able to participate in the CEIP 

in the future. 

7. Independent Verifiers 

The EPA has determined in the final EGs that independent 

verification requirements are necessary to ensure the integrity 

of any rate-based emission trading program, given the types of 

eligible measures that may generate ERCs and the broad 

geographic locations in which those measures may occur. 

Inclusion of an independent verification component provides 

technical support for the EPA in the context of the proposed 

federal plan, and the states in the context of their plans, to 

ensure that eligibility applications and monitoring and 

verification reports are appropriately reviewed prior to 
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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 

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, in the same way 

that only verifiers approved by a state may be eligible to 

perform verification services pursuant to a state plan.67 

 

67 In this section, the term “verifier” is used interchangeably to 

refer to both a “verification body” (i.e., a verification company 
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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 

which they have a financial, management, or other interest.68

 

or organization) and a “verifier,” which is an individual that is 

a principal or employee of a verification body. 

68 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 
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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 

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 

 

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. 
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outside organization where such outside accreditation 

demonstrates that federal plan requirements are met.69 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 

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 

 

69 An example is 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?menuID

=200. 
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adjust an emission rate.70

 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 photovoltaics (PV), concentrated solar power, geothermal 

power, hydropower, new nuclear units and capacity uprates at 

existing nuclear units, and 2) they can provide quantified 

generation data from a revenue quality meter. The language 

pertaining to all other measures (e.g., demand-side EE) is 

proposed only for the model rule. While they are currently being 

 

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

analytic approaches used to quantify the MWh from RE, demand-side 

EE, and other eligible measures and thereby ensure that the 

resulting savings and generation are quantifiable and verifiable. 

In this proposal, we are proposing EM&V for the eligible RE, and 

taking comment on EM&V for demand-side EE and any other measures 

that could be eligible. 
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proposed as part of the model rule and not the federal plan, the 

EPA requests comment on the inclusion of other RE measures, 

demand-side EE measures, and any other measures that may be 

eligible under the final guidelines as eligible measures under 

the federal plan. For stakeholders that are submitting comments 

on the inclusion of such additional measures, the EPA requests 

comment on how the EPA could implement across applicable 

jurisdictions a rigorous, straightforward, and widely 

demonstrated set of EM&V methods, procedures, and approaches 

that could be implemented in the time frame allowed by the 

federal plan and that also meet the requirements outlined in the 

final guidelines. To the extent proposed for inclusion in the 

model trading rule, we also invite comment on these requirements 

in the context of state implementation as part of a state plan. 

Thus, commenters on this aspect of the proposal should consider 

whether and how these provisions could be implemented at the 

state level. Comments that suggest an approach not authorized by 

the EGs will likely be considered out of scope of this action. 

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 
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specified, or may submit alternative EM&V that is functionally 

equivalent to the industry best-practices described as 

presumptively approvable.71 

As discussed in section IV.C.3 of this preamble, quantified 

and verified MWh of RE generation and other means of generating 

ERCs may be used to adjust a CO2 emission rate when demonstrating 

compliance with the emission guidelines. 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.72 

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, 

 

71 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. 

72 A full discussion of applicable requirements for the 

establishment and functioning of the rate-based trading system is 

provided above, in section &&& of this preamble. 
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sources, and resource providers quantify and verify MWh savings 

and generation resulting from zero-emitting RE and demand-side 

EE efforts. This federal plan proposes those requirements that 

the EPA committed to establish. The Clean Power Plan proposal 

and associated “State Plans Considerations” TSD73 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 

 

73 See discussion beginning on p. 34 of the State Plan 

Considerations TSD for the Clean Power Plan Proposed Rule: 

http://www2.epa.gov/carbon-pollution-standards/clean-power-planproposed-rule-state-plan-considerations. 
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consistent with and leverage prevailing industry best-practices. 

In addition, the EPA’s proposed EM&V methods, procedures, 

and approaches reflect several overarching objectives and 

principles offered by states, private organizations, and the 

public during the comment period of the CPP EGs. One of these is 

the importance of balancing the accuracy and reliability of 

results with the associated costs of EM&V. Another objective for 

the EPA’s proposed EM&V is to avoid excessive interference with 

existing practices that are already robust, transparent and 

effective. 

(1) Submittals. 

Applicable submittals under a rate-based emission trading 

program include eligibility applications (including EM&V plans), 

monitoring and verification reports, and verfication reports. 

These submittals are described in section VIII.K.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 
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the requirements were applied. These reports must also specify 

the resulting MWh savings or generation values, as determined on 

a retrospective (ex-post) or real-time basis. MWh values may not 

be determined using projections or other ex-ante quantification 

approaches. 

Each EM&V plan submitted in support of an eligibility 

application must identify the eligible resource covered by the 

plan, and provide specific EM&V criteria that specify the manner 

in which the energy generated or saved by the eligible resource 

will be quantified, monitored and verified. The manner of 

quantification, monitoring and verification must meet the 

criteria outlined below and included in the proposed model rule, 

as applicable to the specific eligible resource. We take broad 

comment on each criteria specified below and in the proposed 

model rule, for each eligible resource. Specifically, we seek 

comment on the substantive content of the criteria. 

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 
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following M&V report must then identify the time period covered 

by the M&V report, describe how the methods specified in the 

EM&V plan were applied during the reporting period, and document 

the quantify (in MWh) of energy generation and/or electricity 

savings quantified and verified for the period covered by the 

M&V report. Any change in the energy generation or savings 

capability of the eligible resource during the period covered by 

the M&V report must also be included in the M&V report, along 

with the date on which the change occurred, and information 

sufficient to demonstrate whether the eligible resource 

continued to meet all eligibility requirements during the period 

covered by the M&V report. Any change should also be specified 

in the report. The EPA takes broad comment on each of these 

criteria, as described here and in the proposed model rule. 

Specifically, we seek comment on the substantive content of the 

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 
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forth the findings of the verifier, based on an assessment of 

all relevant requirements, information and data, including an 

assessment of any material misstatements or data discrepancies. 

Any verification report included as part of an eligibility 

application must further describe the review conducted by the 

verifier and verify the following: the eligibility of the 

resource to be issued ERCs; that the eligible resource exists 

and has been, or will be, generating energy or saving 

electricity in the manner required; that the EM&V plan meets its 

requirements; and any other information required or that the 

verifier finds, in its professional opinion, is necessary to 

assess the accuracy of the subject of the verification report. 

Each verification report included as part of a M&V report must 

also describe the review conducted by the verifier and verify 

the following: the adequacy and validity of the information and 

data submitted to quantify eligible MWh of electric generation 

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 
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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 detail 

provided and whether more or less detail (and what detail) 

should be included in the final model rule, and whether the 

criteria should differ for each eligible resource. 

For demand-side EE, all EM&V plans that are developed for 

purposes of adjusting an emission rate under this final rule are 

intended to leverage and closely resemble the plans already in 

routine use for a wide range of publicly or rate-payer funded EE 

programs and energy service company (ESCO) projects. For RE, 

EM&V plans similarly leverage resources and approaches to MWh 

tracking for RE that are broadly applied in the state and 

regions. The existing reports and documentation from existing 

tracking systems may serve as the substantive basis for a 

monitoring and verification report for RE. 

b. Renewable Energy EM&V Requirements 

This section describes the EM&V requirements associated 

with quantifying electricity generation from eligible RE and 

nuclear, and for documenting these requirements in EM&V plans 
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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 certificate (RECs) and registration of such certificates 

in REC registries. These registries typically include wellestablished safeguards, documentation requirements, and 

procedures for registry operations intended to support the 

demonstration of compliance with state RPS policies. A key 

element of RPS compliance is that each RE generating unit must 

be uniquely identified and recorded in a registry to avoid the 

double counting of RECs. 

The primary metric for all RE is electricity generation, in 

units of MWh. Measured output must be derived either from (1) A 

revenue quality meter that meets the applicable ANSI C-12 

standard or equivalent, which is the typical requirement for 

settlements with RTO and other control-area operators; or (2) 

for customer-sited generators that are interconnected behind the 

customer meter, measurement at the AC output of an inverter, 

adjusted to reflect the energy delivered into either the 

transmission or distribution grid at the generator bus bar. 

Further, a RE generating facility of 10 kW capacity or less may 

estimate the facility’s output if the state where it is located 
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explicitly allows estimates to be used and provides rules for 

when it will be allowed. In the latter case, calculations of 

system output must be based on the RE unit’s capacity, estimated 

capacity factors, and an assessment of the local conditions that 

affect generation levels. All such input parameters and 

assumptions must be clearly described and documented. For RE 

units that are managed by regional transmission operators or 

other control area operators, metered generation data should be 

electronically collected by the control area’s energy management 

system, verified through an energy accounting or settlements 

process, and reported by the control area operator to the REC 

registry at least monthly. The EPA requests comment on this 

proposed requirement for quantifying RE generation for the 

purpose of ERC issuance.

For RE units that do not go through a control area 

settlements process, metered data may be read and transmitted to 

the ERC registry by an independent third party, or may be selfreported. Third-party and self-reported generation data must be 

reported on an annual basis. All such data must be verified for 

reasonableness by the agency, state or the REC registry. 

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 
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uniquely identified in the federal tracking system, the 

nameplate capacity of each RE unit is less than 150 kW, the 

aggregated RE units collectively have nameplate generating 

capacities less than 1.0 MW, the units aggregated are located in 

the same state, the RE units being aggregated utilize the same 

technology/fuel type, and the RE unit’s generation data are 

based on the same metering or the same generation estimating 

software or algorithms. The EPA requests comment on how existing 

reporting systems can play a role in meeting EM&V requirements 

under the federal plan, particularly, in assuring that each MWh 

of RE generation is uniquely identified and recorded to avoid 

double counting. 

An additional criterion that applies to distributed RE 

units that directly serve on-site end-use electricity loads is 

that avoided transmission and distribution (T&D) system losses 

can be considered, as is commonly practiced with demand-side EE. 

Such calculations must apply the requirements specified for 

demand-side EE as described below. 

The EPA requests comment on all metering, measurement, 

verification, and other requirements included in this 

subsection, includuing the appropriateness of their use for each 

type of renewable energy resource (including the relvant size 

and distribution of such resource) that qualifies for issuance 
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of ERCs for use in Clean Power Plan compliance. 

For renewable energy resources with a nameplate capacity of 

10 kW or more and for renewable energy resources with a 

nameplate capacity of less than 10 kW 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 10kW is the appropriate threshold, under which an 

eligible resource can be issued ERCs for generation based on 

data other than metered generation, and if not, what would be 

the appropriate threshold. 

For renewable energy resources of all sizes and means of 

monitoring, we take comment on the appropriate requirements for 

allowing generation data to be aggregated, including comment on 

the provisions in the proposed model rule and any alternatives 

to them. We take comment on whether the all of the generating 

units have the same essential generation characteristics, in 

order for their data to be aggregated, and if so, what the 

appropriate content of the definition of “essential generation 

characteristics” (e.g., are essential generating characteristics 

determined on a resource by resource basis, or can generation 
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from a group of wind turbines be aggregated with generation from 

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

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

nameplate capacity of less than 150 kW 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 kW, we take comment 

on whether the final model rule should specify the specific 

estimating software or algorithms by which generation data 

should be measured, and if so, we take broad comment on the 

appropriate estimating software or algorithms and/or the 

appropriate characteristics for such estimating software or 

algorithms. 

We request comment on any other requirements that should be 

included in the final model rule regarding EM&V of renewable 

energy 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 10kW, at the AC output of the 

inverter or elsewhere), whether measurement should be before or 
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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, 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 
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whether nuclear energy resources should be subject to the same 

EM&V requirements as renewable energy 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 kw, and how to account for 

T&D losses. 

To calculate a CHP unit’s creditable MWh, the electrical 

output is prorated based on the “incremental CO2 emission rate” 

of the CHP unit relative to the applicable CO2 emission rate for 

affected EGUs in the state. The CHP unit’s electrical output 

would be prorated based on the CO2 emission rate of the 

electrical output associated with the CHP unit.74 The incremental 

 

74 The applicable CO2 emission limit rate depends on the type of 

state plan being implemented. Where a state plan includes a single 

CO2 emission limit rate for the fleet of affected EGUs, the 

applicable rate is the rate that applies to all affected EGUs. 

Where a state plan includes subcategorized rates for different 

categories of affected EGUs, the applicable rate is the rate that 

applies to affected NGCC EGUs. 
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rate would be relative to the applicable CO2 emission rate 

standard for affected EGUs in the state and would be limited to 

values between 0 and 1. 

Prorated MWh = (1 – incremental CHP emission 

rate/applicable affected EGU emission standard rate) * CHP MWh 

output, where the ratio is limited to values between 0 and 1. 

The CHP electrical emission rate is the net emission rate 

when the CHP unit’s thermal output emissions are deducted from 

the CHP unit’s total emissions. It can be derived as follows 

[CHP fuel input * fuel emission factor – (UTO/boiler 

efficiency) * fuel emission factor]/CHP MWh 

In order to determine the incremental CO2 emission rate, a 

CHP unit would monitor requirements for CO2 emissions and energy 

output.75 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 facilities76 with electric generating 

capacity greater than 25 MW would follow the same monitoring and 

reporting protocols for CO2 emissions and energy output as are 

 

75 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.’ 

76 A CHP facility may consist of one or more electric generators. 
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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 75 is acceptable. 

The EPA requests comment on all metering, measurement, 

verification, and other requirements included in this subsection 

with respect to CHP, including the appropriateness of their use 

for CHP (including with respect to the size of the CHP 

resource). We take comment on whether a CHP unit should be 

subject to the same EM&V requirements as renewable energy 

resources, and we take comment on any additional EM&V 

requirements to which CHP units should be subject. Specifically, 

we take comment on specifying in the final model rule that if a 

combined heat and power 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 combined heat and power unit has an electric 

generating capacity less than or equal to 25 MW, the EM&V plan 

must specify that it will meet the low mass emission unit CO2

emission monitoring and reporting methodology in 40 CFR 75. We 
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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 

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 
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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 presumptively approvable. The EPA may approve 

other requirements of similar rigor, at its discretion. An EM&V 

plan that addresses the biogenic CO2 emissions from a waste-toenergy facility must follow the requirements for monitoring and 

reporting biogenic CO2 emissions from the facility that were 

approved by the EPA in connection with the specific state plan. 

As discussed in the final EGs (see section VIII.K.1 of the 
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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 renewable energy 

resources, and we take comment on any additional EM&V 

requirements to which waste-to-energy resources should be 

subject, including comment on any specific methods for 

determining the specific portion of the total net energy output 

from the resource that is related to the biogenic portion of the 

waste that the EPA should include in the final model rule. 

g. Demand-Side Energy Efficiency EM&V Provisions 

 The following section describes presumptively approvable 

EM&V provisions that may be included in state regulations 

governing how EE is quantified by EE providers and is verified 

by independent entities acting on behalf of the state. These 

provisions apply to all demand-side EE used to adjust an 

emission rate. 

For all demand-side EE used to generate ERCs, the metric is 
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MWh of electricity savings, which is quantified on an ex-post 

basis and defined as a reduction in facility- or premises-level 

electricity consumption due to an EE program, project, or 

measures. 

(1) Common Practice Baseline 

Based on public input and assessments of industry bestpractice protocols and procedures, the EPA has determined that a 

presumptively approvable EM&V provision is quantifying EE saving 

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 – or that a typical consumer or building 

owner would have continued using – in a given circumstance 

(i.e., a given building type, EE program type or delivery 

mechanism, and geographic region) at the time of EE

implementation. It defines what would commonly have happened in 

the absence of the EE intervention. 

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

characteristics of the EE measure, the delivery mechanism to 

implement the EE measure, local consumer and market

characteristics, and the applicable building energy codes and 

product standards (C&S), including the C&S compliance rate. 

Examples of appropriate CPBs to apply in specific contexts, with 
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consideration of these factors, can be found in the EPA’s draft 

EM&V guidance. EE providers must document the selected CPB in 

their EM&V plans, along with clear documentation and discussion 

of the rationale, applicability, and relevant data sources, 

protocols, and other supporting information.77 Monitoring and 

verification reports must refer to the EM&V plan and confirm 

that the CPB was applied. 

(2) Methods Used to Quantify Savings from Energy Efficiency 

Programs and Projects 

This section discusses presumptively approvable provisions 

for the general types of EM&V methods that EE providers may use 

to quantify the MWh savings from demand-side EE programs, 

projects, and measures. During the CPP EG’s public comment 

period, the EPA received input indicating that state PUCs 

typically allow utilities and other EE providers to use a range 

of EM&V methods that reflect applicable circumstances and onthe-ground conditions (versus mandating which methods must be 

used in a particular situation). Consistent with this approach, 

the EPA’s presumptively approvable provisions offer flexibility 

 

77 For one source of applicable baselines, see Table 7.1. State and 

Local Energy Efficiency Action Network. 2012. Energy Efficiency 

Program Impact Evaluation Guide. Prepared by Steven R. Schiller, 

Schiller Consulting, Inc., http://www.seeaction.energy.gov. Or 

current version. 
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for EE providers to select from three broad categories of EM&V 

methods to determine savings. 

These categories include project-based measurement and 

verification (M&V), deemed savings, and comparison group 

approaches such as randomized control trials (RCT). Regardless 

of the approach selected, the EPA is proposing that annual 

savings values must be quantified using these EM&V methods at 

specified time intervals (in years) on a recurring basis over 

the effective useful life of the EE project or measure in order 

to ensure accurate and reliable savings values. To be considered 

presumptively approvable, EE providers must conduct 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 rate-payer funded EE programs, depending on the 

program type, magnitude of savings, and experience with the 

program; and annually for large individual commercial and 

industrial projects, unless the EE provider can credibly 

demonstrate why this is not possible and how the accuracy and 

reliability of savings values will be maintained. For all 

demand-side EE used to adjust an emissions rate, the selected 

method, associated assumptions, and data sources must be 

identified and described in EM&V plans. 

For comparison group approaches, EE providers can refer to 
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the EPA’s draft EM&V guidance for a discussion of industry bestpractice protocols and guidelines, such as those published by 

the SEE Action Network and the U.S. DOE’s Uniform Methods 

Protocols (UMP) project. Where feasible, the EPA seeks 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 presumptively approvable provisions are that 

deemed values (a) be 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) be updated at a 

minimum of every 3 years to reflect the per-measure MWh savings 

documented in ex-post EM&V studies apply measurement and 

verification or comparison group methods. 

For M&V methods, the presumptively approvable provision is 

that industry best-practice protocols must be followed. These 
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include the International Performance Measurement and 

Verification Protocol (IPMVP), protocols published by the 

Federal Energy Management Program (FEMP), the American Society 

of Heating, Refrigeration and Air-Conditioning Engineers 

(ASHRAE), and the U.S. DOE’s UMP. EE providers can consult the 

EPA’s EM&V guidance to assess the applicability of such 

protocols and guidelines to the EE programs and projects 

generating savings, and must document how these will be applied 

in EM&V plans (along with clear documentation and discussion of 

the rationale, applicability, and relevant data sources, and 

other supporting information). Monitoring and verification 

reports must refer to the EM&V plan and confirm that the 

relevant protocol was applied. 

(3) Quantifying Savings 

Regardless of the approach used to quantify and verify MWh 

savings, EM&V plans must describe how they will address the 

following presumptively approvable provisions: 

• How major changes in independent variable conditions 

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

affect energy consumption and savings estimates will 

be analyzed. The effects of these changes must be 

calculated using industry best-practices such as realtime 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 

consumer-funded EE programs and project-based EE are 

evaluated site-by-site). Verification is required 

within the first year of program implementation. All 

verification activities must be performed using 

industry best-practice techniques (e.g., phone or mail 

surveys, document review, site inspections, spot or

short-term metering). For projects implemented as part 

of a program, verification can be performed using a

sample of projects to represent the full program 

population. 

• How avoided T&D system losses78 will be quantified and 

applied to EE savings determined at the customer 

facility or premises. Demand-side EE programs (other 

than T&D efficiency measures such as CVR and volt/VAR 

 

78 T&D losses are defined as the difference between the quantified 

EGU generation required to serve a customer’s load (measured at 

the EGU bus bar) and the customer’s actual electricity consumption 

(measured at the customer meter). 
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optimization79) may adjust reported savings by using a 

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

presumptively approvable appraoch 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.80 

• How the duration of EE program or project electricity 

savings will be determined. This must be determined

using industry best-practice protocols and procedures 

such as annual verification assessments, industrystandard persistence studies, deemed estimates of 

effective useful life (EUL), or a combination of all 

three. 

• How the accuracy and reliability of quantifying MWh

 

79 More information about these technologies is in section VIII.F.1 

of this preamble above. 

80 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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savings values will be assessed, and the rigor81 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 

 

81 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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this observation and is therefore proposing the application of 

industry best-practice protocols and procedures for demand-side 

EE. A presumptively approvable provision for EM&V plans is that 

they must include a clear description and documentation of how 

the relevant protocols will be applied, as well as after-thefact documentation in EM&V reports of how they were actually 

applied. EE providers can refer to the EPA’s EM&V guidance 

document for information about protocols that are considered 

“industry best-practice protocols and procedures.”

(5) Eligible Demand-Side Energy Efficiency Programs and Projects. 

 There has been stakeholder interest expressed through the 

CPP EG rulemaking process in accounting methods for quantified 

and verified MWh savings from DS-EE in state plans. Consistent 

with these perspectives, the EPA position is that any demandside EE program and project that results in MWh savings may be 

potentially eligible to states, including under this proposed 

model trading rule, provided that it meets the presumptively 

approvable provisions for eligibility described in section 

IV.C.3 of this preamble, and that supporting EM&V is rigorous, 

complete and fulfills the requirements provided in the emission 

guidelines and the state plan. 

Common demand-side EE programs and project types include: 

• Publicly or consumer-payer funded customer-funded 
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demand-side management programs, including those 

implemented in low-income residences and facilities. 

• Project-based EE evaluated site-by-site, for example 

those implemented by ESCOs at commercial buildings and 

industrial facilities. 

• State and local government building energy code and

compliance programs. 

• State and local government incremental product energy 

standards. 

The EPA’s EM&V guidance contains supplemental information 

about applicable 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 emission guidelines. 

(6) Requests for Comment on Energy Efficiency EM&V 

We take broad comment on each EE EM&V criteria described 

herein and in the proposed rule text, for each type of EE 
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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 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 proposed simultaneously with this proposed 

rulemaking should instead be included in the final model rule, 

instead of in guidance. 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 

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

what constitute EE best practices protocols for every type of EE 

activity, project, program, or measure. 

We take broad comment on 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 take broad comment on the appropriateness of quantifying 
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electricity savings by applying one or more of the following 

methods and comment on all aspects of each method: project-based 

measurement and verification (PB-MV), comparison group 

approaches, or deemed savings. We take further comment on 

circumstances in which it is appropriate (or inappropriate) to 

use each of these methods, including when it is appropriate to 

use random control trials 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 cost-effective manner). 

 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. We further take comment on the presumptively 

approvable provision for public access and input to the 

development of the TRMs used to house the applicable deemed 

savings values. 

We take comment on the minimum and maximum intervals (in 

years) over which electricity savings must be quantified, 

including those time intervals specified in the proposed model 

rule, and we take comment on any factors that must be taken into 
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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 build off of these programs 

if they incorporated EE into a rate-based trading scheme with 

ERCs, it is theoretically possible that an ERC could be issued 

in one state that would not have been issued in another, even if 

both states have rate-based programs in place that meet all of 

the emission guidelines. 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 activity, 

project, program, measure in one state reflects the same 1 MWh 

of energy or electricity saved in another state. We further take 

comment on whether there are provisions that the EPA should 

include in the final model rule that would prevent an entity 

seeking to be issued an ERC (whether from EE or energy 

generation) from forum shopping, in an effort to find a state 

with standards for ERC issuance that it deems less burdensome 

than those in another state.

We take comment on how to appropriately consider factors 

that affect energy savings in the quantification and 

verification process, including those identified in the proposed 
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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 

(such as 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 results, including the necessary rigor of the method 

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 measure the transmission and distribution loss 

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

savings 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 expressed as a percentage. We 

take comment on the appropriateness of including such a 

restriction in the final model rule that no other transmission 

and distribution loss factors may be used in calculating the 

electricity savings. 

We take comment on any additional criteria that we should 

include in the final model rule regarding EE EM&V. 

h. Skill Certification Standards 

Using a skilled workforce to implement demand-side EE and 

RE projects and other measures intended to reduce CO2 emissions, 

and to evaluate, measure and verify the savings associated with 
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EE projects or the additional generation from performance 

improvements at existing EGU’s are both important. Several 

commenters pointed out that skill certification standards can 

help to assure quality and credibility of demand-side EE,RE and 

other carbon emission reduction projects. The EPA also 

recognizes that a skilled workforce performing the EM&V is 

important to substantiate the authenticity of emissions 

reductions. 

 The EPA agrees that in conjunction with other EM&V

measures discussed in this section, and in the context of the 

model trading rules although this is not an aspect needed for 

presumptive approvability, states are encouraged to include in 

their plan a description of how states will ensure that workers 

installing demand side EE and RE projects, or other measures 

intended to reduce CO2 emissions, as well as workers who perform 

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 
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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 

Department of Energy’s (DOE) Better Building Workforce 

Guidelines and validated by a third party accrediting body 

recognized by DOE; or parties aligned with an apprenticeship 

program that is registered with the federal Department of Labor 

(DOL), Office of Apprenticeship; or with a state apprenticeship 

program approved by the DOL, or by another skill certification 

validated by a third party accrediting body can help to 

substantiate the authenticity of emission reductions due to 

demand-side EE and RE and other carbon emission reduction 

measures. 

9. ERC Transfers and Trading 

All affected EGUs that may be subject to this proposed 

federal plan would be required to be a part of the allowance 

tracking and compliance system (ATCS) that the EPA runs, 
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although the affected EGUs that are regulated under the ratebased federal plan would use ERCs as a compliance instrument, 

not allowances. To register to participate in the ATCS an 

affected EGU must submit designated representative information. 

More information on the designated representatives is described 

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 

data consistent with part 75.82 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 

 

82 See section IV.D.11 of this preamble for more information. 
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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.E.4 of this 

preamble. The EPA is proposing to issue ERCs annually. ERCs are 

acquired and traded throughout the compliance period. An 

affected EGU is responsible to hold sufficient ERCs that qualify 

for CPP compliance in its ATCS compliance account by November 1 

at midnight of the year following the conclusion of the 

compliance period.83 

 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 

 

83 This true-up process is further described in section IV.D.8 of 

this preamble. 
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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 

compliance period. For example, if the first compliance period 

comprises the three years 2022, 2023, and 2024, then the ERC 

transfer deadline84 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 allowance 

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 

 

84 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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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 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 
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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. 

789:;<=8	>?@;;@AB	CD<= = 	

ED;;	AF	GH2	=?@<<=8	IJ;

K=B=LD<@AB	EMh + EMh	>CG;

This equation can be rearranged to: 

EMh	>CG; = 	

ED;;	AF	GH2	=?@<<=8	IJ;

789:;<=8	>?@;;@AB	CD<=	 IJ;

EMh

− K=B=LD<@AB	EMh

If an affected EGU fails to hold sufficient ERCs to comply 

with its emission standard then, upon notification of the 

deficiency, the owners and operators of the affected EGU must 

provide, for deduction by the Administrator, two ERCs as soon as 

available for every ERC that the owners and operators failed to 

hold as required to cover emissions, in addition to the ERCs 

owed for compliance in that next period. The owed ERCs will be 

deducted from the EGU’s compliance account as soon as they are 

available in this account; the Administrator will not wait until 

the next true-up date to make this deduction. The two ERCs owed 

for each ERC needed for compliance is in addition to any other 

recourse provided in sections 113 (a)–(h) or section 304 of the 

CAA. This requirement to surrender two times the ERCs needed to 

make up the shortfall for the prior period is an ongoing 
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obligation until compliance is achieved, and there is an ongoing 

obligation to comply in the current period. Failure to surrender 

these replacement ERCs is an additional violation that may be 

subject to federal enforcement. The EPA solicits comment on 

sources owing two ERCs to make up for each insufficient ERC in 

previous compliance periods and whether two for one is the 

proper make-up rate or whether there should be a stricter or a 

more lenient ratio. 

The EPA believes that it is important to include a 

requirement for an automatic deduction of ERCs. The deduction of 

one ERC per ERC that the owners and operators failed to hold 

would offset this failure. The deduction of another ERC per ERC 

that the owners and operators failed to hold provides a strong 

incentive for compliance with the ERC-holding requirement by 

ensuring that non-compliance would be a significantly more 

expensive option than compliance. This is consistent with other 

existing trading programs. 

11. Other ERC Tracking and Compliance Operations Provisions 

These sections also would provide that the Administrator 

could, at his or her discretion and on his or her own motion and 

consistent with existing federal trading programs, correct any 

type of error that he or she finds in an account in the ATCS. In 

addition, the Administrator could review any submission under 
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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 Acid Rain Program and Cross State Air Pollution Rule (see, 

e.g., 40 CFR 72.96, 73.37, 97.427, and 97.428). The EPA solicits 

comment on potential alternatives for error correction that is 

simpler or more efficient. 

12. Banking of ERCs 

The EPA is proposing to allow unlimited banking or ERCs 

within and between the interim and final compliance periods. 

This means that if an affected EGU has more ERCs than are 

necessary during true-up, it may save (i.e., bank) those ERCs 

for application during a future compliance period. The EPA 

requests comment on whether there should be a quantitative limit 

or cap on the number of ERCs that can be banked. The EPA also 

requests comment on whether an ERC should be eligible to be 

banked between the interim and final compliance periods. The EPA 

is also proposing that ERCs will not expire after any duration 

of time. Other trading rules that the EPA has instituted (e.g., 

CSAPR) do not have expiration on the tradable properties. The 

EPA requests comment on the shelf-life of an ERC. 

ERC “borrowing” is a flexibility that the EPA is not 
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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 

monitor and report CO2 emissions by and output data by January 1, 

2022. Quarterly reporting would be required, with each quarterly 

report due to the Administrator 30 days after the last day in 

the quarter. The reporting would be in accordance with 40 CFR 

part 75.60. The use of part 75 certified monitoring

methodologies would be required. Many affected EGUs that might 
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be covered by the proposed federal plans will generally have no 

changes to their monitoring and reporting requirements and will 

continue to monitor and submit reports under part 75 as they 

have under existing programs. The EPA anticipates fewer than 50 

(approximately 10 of these affected EGUs are coal fired with the 

remainder being gas and oil fired that will qualify for an 

excepted monitoring methodology) affected EGUs, that would not 

otherwise be subject to the Acid Rain Program, 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. Several of the 

affected EGUs not otherwise subject to the Acid Rain Program are 

subject to the MATS program and therefore will have already 

installed stack flow rate and/or CO2 monitors in order to comply 

with the MATS rule which are also necessary to comply with this 

rule. The CEMS used to comply and report data for MATS will be 

used for this rule to generate and report CO2 emissions data 

without having to install duplicative monitors. The same CO2 and 

stack gas flow rate monitored data used in conjunction with Hg 

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 
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and ARP currently require the reporting of CO2 mass emissions on 

an hourly basis and cumulative totals at the end of each 

calendar quarter. The same monitors and data collected may be 

used for multiple purposes for RGGI, ARP, MATS and this rule. 

Relying on the same monitors that are certified and quality 

ensured in accordance with 40 CFR part 75 ensures cost 

efficient, consistent, and accurate data that may be used for 

different purposes for multiple regulatory programs. The 

majority of the affected EGUs covered by this rule are already 

affected by the Acid Rain and/or Regional Greenhouse Gas 

Initiative programs and will have minimal additional monitoring 

and reporting requirements. 

The EPA also requests comment on requiring monitoring and 

reporting of CO2 mass and net generation for the year before the 

initial compliance period begins, i.e., to commence January 1, 

2021. Only monitoring and reporting would be required in 2021 — 

compliance with an enforceable emission standard would commence 

on the compliance period schedule that is detailed in section 

IV.E.3 of this preamble. 

E. Federal Plan and State Plan Interactions 

1. Interstate Trading 

The EPA proposes that all affected EGUs within states that 

are covered by the federal plan, if a rate-based federal plan is 
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finalized for two or more states, would be allowed to trade with 

one another since there will be an assured commonality in the 

ERC currency and criteria surrounding the trading program. In 

addition, the EPA proposes, consistent with the provision for 

“ready-for-interstate-trading” plans in the EGs that affected 

EGUs located in states with approved ready-for-interstatetrading state plans using the sub-categorized uniform rate 

standards, and a common credit currency (i.e., ERCs representing 

one zero-emitting MWh) may trade with affected EGUs operating 

under the federal trading program established in this federal 

plan. 

Rate-based EGUs subject to the federal plan and rate-based 

EGUs in ready-for-interstate-trading state plans will be able to 

trade ERCs seamlessly across jurisdictional borders because of 

the assurances of being presumptively approvable. Ready-forinterstate-trading states must submit information that lists all 

affected EGUs and the EGU type to the Administrator to be able 

to trade within the federal trading program. To be able to trade 

in the federal trading program an affected EGU that is subject 

to a ready-for-interstate-trading state plan must: (1) Certify 

and authorize a designated representative per section IV.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 
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ERCs with entities operating in the federal trading program. An 

affected EGU under a state plan will not register a compliance 

account in the federal system because it will not be 

demonstrating compliance under the federal plan. Compliance will 

be achieved in the EGU’s corresponding state plan. Affected EGUs 

under a state plan have the ability to acquire ERCs through the 

federal trading program. These ERCs will be stored in the EGU’s 

general account in the federal trading program. To use these 

ERCs for compliance purposes, the ERCs must be transferred to 

the EGU’s compliance account in the state’s program. The EPA 

proposes to provide software to states to maintain a state’s 

compliance and tracking program. A state’s program will have the 

capability to interact with the federal trading program and 

software, ATCS, for transferring ERCs if the state is ready-forinterstate-trading. A state’s program can be tailored to meet 

its needs while still providing a platform for a state to be 

transferring ERCs between the state’s system and the federal 

trading program. ERCs can flow between a state system and the 

federal trading program bilaterally. The EPA acknowledges that 

states may have additional criteria for generating ERCs that are 

not outlined as part of the federal plan, but because the EPA 

will have vetted these criteria through a state plan approval 

these ERCs will be able to be traded within the federal trading 
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program. 

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

The EPA proposes that a rate-based trading federal plan may 

be replaced by a state plan for a future compliance period. The 

EPA is proposing that a state must transition to a state plan at 

the conclusion of a federal plan compliance period. The EPA 

requests comment on whether there are reasons that a state 

should be allowed to transition from a federal plan to a state 

plan in the middle of a compliance period and if so what 

requirements should be put in place to do so while ensuring the 

integrity of both the federal plan and the state plan and while 

enabling the affected EGUs covered by the plans to understand 

and meet their compliance requirements. If a state subject to 

the federal plan transitions to a state plan, any affected EGU 

impacted by the change remains responsible for meeting any 

outstanding obligations under the federal plan. To make the 

transition to a state plan, a state must have an approved state 

plan as laid out in 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 
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that participate in the market. A mass-based trading program 

provides sources with great flexibility in choosing compliance 

strategies. 

In the proposed mass-based trading program for the federal 

plan, the aggregate emissions limit for a state is its statewide 

mass-based emission goal (or “mass goal”) as finalized in the 

Clean Power Plan EGs. The proposed approach to linking states 

for interstate allowance trading is detailed in section III.A.1 

of this preamble; in an interstate trading program the aggregate 

emissions limit is the sum of the mass goals for the covered 

states. 

The EPA believes that a broad trading region provides 

greater opportunities for cost-effective implementation of 

controls compared to a smaller region. Therefore, the agency 

proposes that an affected EGU in any state covered by the 

proposed mass-based trading federal plan may use for compliance 

an allowance distributed in any other state covered by the massbased trading federal plan. The EPA also proposes to provide for 

allowance trading between affected EGUs and other entities in 

states with approved mass-based-trading state plans that meet 

the conditions specified in section III.A.1 of this preamble, 

above, and affected EGUs and other entities in any state covered 

by the federal plan mass-based trading program. 
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 A mass-based trading program can provide environmental 

certainty at lower cost than other policy mechanisms, because it 

assures the specified emissions outcome while maximizing 

compliance flexibility available to individual affected EGUs. 

Further, allowance banking in such a program creates an 

incentive to make reductions earlier than required. Mass-based 

trading programs are relatively simple to operate, which reduces 

administrative time and cost. Additionally, to inform the massbased trading approach proposed here, the EPA draws upon more 

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

including the Acid Rain Program SO2 trading program, the NOX

Budget Trading Program, the CAIR, and the 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 
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state allocation has important merits. The EPA would distribute 

allowances in a state if the state does not choose to do so, as 

detailed below. 

Each allowance would authorize the emission of one short 

ton of CO2 during the compliance period applicable to the 

allowance’s vintage year or a later compliance period. The 

proposed approach to distribute allowances, including three 

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

this preamble, below. 

After each compliance period, an affected EGU would

surrender for compliance an amount of allowances equal to its 

emissions during the course of the compliance period. See 

section V.C of this preamble for the proposed length of the 

multi-year compliance periods. Allowances could be transferred, 

bought, sold, or banked (carried over for future use) and any 

party could participate in the allowance market. The EPA is not 

proposing allowance “borrowing” (i.e., the bringing forward of 

future-period allowances for use in an earlier period); the 

multi-year compliance periods inherently provide the flexibility 

to schedule relatively greater emission reductions for later 

years within each period, as discussed further in section V.C of 

this preamble. In the proposed mass-based trading program, the 

emission standard applied to individual affected EGUs is the 
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requirement to surrender emission allowances equal to reported 

emissions for each compliance period. 

The EPA also proposes that a state may choose to replace 

the federal-plan allowance-distribution provisions with its own 

allowance-distribution provisions (i.e., to determine the 

distribution of allowances for its EGUs or other entities) using 

a state allowance-distribution methodology. State allowance 

distribution can have important advantages, because it allows a 

state to design and shape allowance allocation to its specific 

goals and characteristics, and because states may have 

additional flexibility on allocation approaches, including 

auctions. See section V.E of this preamble for further 

discussion of the proposed approach for state-determined 

allowance-distribution methodologies. 

This proposed requirement to hold and surrender allowances 

equal to emissions for each compliance period would apply to all 

reported emissions from a facility’s affected EGUs including any 

emissions from co-fired biomass if biomass is included as an 

eligible measure. Section IV.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 
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control increases of CO2 levels in the atmosphere) and potential 

methods for demonstrating compliance, and thus reduce the mass 

emissions attributed to a biomass co-fired affected EGU. If the 

EPA took such an approach, then for purposes of compliance with 

the proposed mass-based federal plan trading program, the 

affected EGU would need to hold allowances equal to its 

emissions less the emissions attributed to the co-fired 

qualified biomass; such an approach would reduce the number of 

allowances the affected EGU would need to hold to demonstrate 

compliance. The EPA requests comment on this approach. 

B. Statewide Mass-based Emissions Goals 

In the Clean Power Plan EGs the EPA established statewide 

mass-based emission goals (“mass goals”) for all states that are 

equivalent to the rate-based goals. As discussed in section V.C 

of this preamble, below, the EPA proposes to implement the massbased trading program with multi-year compliance periods that 

are consistent with the compliance timing provisions in the 

Clean Power Plan EGs, i.e., two three-year compliance periods 

followed by a 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 
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mass limits (i.e., emissions budgets) for any state covered by 

the mass-based trading program (or, if implementing interstate 

trading, then the EPA would use the sum of a covered group of 

states’ mass goals as the aggregate mass limit). The EPA is not 

opening for comment the determinations, made in the Clean Power 

Plan EGs, of each state’s mass goals. The mass goals are 

provided for convenience in Table 8of this preamble. 

Table 8. Statewide Mass-Based Emission Goals (“Mass Goals”) 

(Short Tons) 

State 

 Interim period Final 

period 

 Step 1 

2022-2024 

 Step 2 

2025-2027 

 Step 3 

2028-2029 

 2030-2031

and 

thereafter 

Alabama 

 

66,164,470 

 

60,918,973 

 

58,215,989 

 

56,880,474 

Arizona 

 

35,189,232 

 

32,371,942 

 

30,906,226 

 

30,170,750 

Arkansas 

 

36,032,671 

 

32,953,521 

 

31,253,744 

 

30,322,632 

California 

 

53,500,107 

 

50,080,840 

 

48,736,877 

 

48,410,120 

Colorado 

 

35,785,322 

 

32,654,483 

 

30,891,824 

 

29,900,397 

Connecticut 

 

7,555,787 

 

7,108,466 

 

6,955,080 

 

6,941,523 

Delaware 

 

5,348,363 

 

4,963,102 

 

4,784,280 

 

4,711,825 

Florida 

 

119,380,477 

 

110,754,683 

 

106,736,177 

 

105,094,704 

Georgia 

 

54,257,931 

 

49,855,082 

 

47,534,817 

 

46,346,846 

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 
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Indiana 

 

92,010,787 

 

83,700,336 

 

78,901,574 

 

76,113,835 

Iowa 

 

30,408,352 

 

27,615,429 

 

25,981,975 

 

25,018,136 

Kansas 

 

26,763,719 

 

24,295,773 

 

22,848,095 

 

21,990,826 

Kentucky 

 

76,757,356 

 

69,698,851 

 

65,566,898 

 

63,126,121 

Lands of the Fort Mojave 

Tribe 

 

636,876 

 

600,334 

 

588,596 

 

588,519 

Lands of the Navajo Nation 

 

26,449,393 

 

23,999,556 

 

22,557,749 

 

21,700,587 

Lands of the Uintah and Ouray 

Reservation 

 

2,758,744 

 

2,503,220 

 

2,352,835 

 

2,263,431 

Louisiana 

 

42,035,202 

 

38,461,163 

 

36,496,707 

 

35,427,023 

Maine 

 

2,251,173 

 

2,119,865 

 

2,076,179 

 

2,073,942 

Maryland 

 

17,447,354 

 

15,842,485 

 

14,902,826 

 

14,347,628 

Massachusetts 

 

13,360,735 

 

12,511,985 

 

12,181,628 

 

12,104,747 

Michigan 

 

56,854,256 

 

51,893,556 

 

49,106,884 

 

47,544,064 

Minnesota 

 

27,303,150 

 

24,868,570 

 

23,476,788 

 

22,678,368 

Mississippi 

 

28,940,675 

 

26,790,683 

 

25,756,215 

 

25,304,337 

Missouri 

 

67,312,915 

 

61,158,279 

 

57,570,942 

 

55,462,884 

Montana 

 

13,776,601 

 

12,500,563 

 

11,749,574 

 

11,303,107 

Nebraska 

 

22,246,365 

 

20,192,820 

 

18,987,285 

 

18,272,739 

Nevada 

 

15,076,534 

 

14,072,636 

 

13,652,612 

 

13,523,584 

New Hampshire 

 

4,461,569 

 

4,162,981 

 

4,037,142 

 

3,997,579 

New Jersey 

 

18,241,502 

 

17,107,548 

 

16,681,949 

 

16,599,745 

New Mexico 

 

14,789,981 

 

13,514,670 

 

12,805,266 

 

12,412,602 

New York 

 

35,493,488 

 

32,932,763 

 

31,741,940 

 

31,257,429 

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 
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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 greenhouse gas mass-based trading programs 

(i.e., emissions budget trading programs) use multi-year 

compliance periods. The Regional Greenhouse Gas Initiative 

(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-
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year compliance period; at the end of each 3-year compliance 

period sources must hold allowances to cover 100 percent of 

emissions for the period and allowances already deducted for the 

intervening requirement are subtracted from the 3-year 

obligation.85 The California Air Resources Board (CARB) Cap-andTrade 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.86 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 long-

 

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

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

le_Summary.pdf Accessed June 9, 2015. 

86Overview 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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standing CAA precedent, “[t]he time over which [the compliance 

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

generally not exceed one month.” See e.g., June 13, 1989 

Guidance on Limiting Potential to Emit in New Source Permitting 

and January 25, 1995 Guidance on Enforceability Requirements for 

Limiting Potential to Emit through SIP and §112 Rules and 

General Permits. The EPA determined that the longer compliance 

periods provided for in this rulemaking are acceptable in the 

context of this specific rulemaking because of the unique 

characteristics of this rulemaking, including that CO2 is longlived in the atmosphere, and this rulemaking is focused on 

performance standards related to those long-term impacts. 

The EPA proposes that allowances may be banked for use in 

any future compliance period, with no restriction on the use of 

banked allowances, including from the Interim Period (2022 

through 2029) into the Final Period (2030 and thereafter). The 

agency requests comment on the proposal to provide for unlimited 

allowance banking including the banking of Interim-Period 

allowances for use during the Final Period. 

Allowance “borrowing” is a type of timing flexibility 

wherein allowances from a future compliance period may be 

“brought forward” and used for compliance in an earlier 

compliance period (thus reducing the amount of allowances 
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available for the future period). The EPA notes that the 

proposed multi-year compliance periods inherently provide the 

flexibility to emit at relatively higher amounts in earlier 

years of a given compliance period by using allowances from 

future years within each compliance period (e.g., if the first 

compliance period covers years 2022 through 2024, a vintage 2024 

allowance could be used to cover a ton emitted in 2022). The EPA 

is not proposing to allow allowance borrowing across compliance 

periods in the mass-based trading federal plans; however the 

agency is requesting comment on the use of borrowing across 

compliance periods. Allowance borrowing across compliance 

periods would increase the complexity of the proposed mass-based 

trading program and reduce the flexibility for states to replace 

the federal plan with an approved state plan. First, in order 

for borrowing to occur, the EPA would have to make allowances 

from future compliance periods available early so that sources 

could use these future allowances in earlier compliance periods. 

The EPA proposes to record allowances in source accounts for one 

compliance period at a time in order to maximize the 

opportunities for a state to replace the federal plan (or 

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 
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replace the mass-based trading federal plan (or the federal-plan 

allowance-distribution provisions) with a state plan (or state 

allowance-distribution methodology) for a compliance period for 

which the agency has not yet recorded allowances in source 

accounts. Recording allowances for multiple compliance periods 

at once – in order to make future-period allowances available 

for borrowing – would therefore limit these opportunities for 

states to take over implementation (or implementation of the 

allowance-distribution). 

If allowance borrowing from a future compliance period were 

allowed, and the EPA provided the opportunity for a state to 

replace the federal plan for a year for which allowances had 

already been borrowed and retired for compliance in an earlier 

period, those borrowed allowances would constitute additional 

emissions beyond the levels specified in the Clean Power Plan 

EGs. In that event, the EPA would then need to address whether 

and how to remove allowances from circulation to prevent 

inflation of the allowable emissions at affected EGUs in the 

remaining states subject to the federal plans (to “repay” the 

borrowed allowances). To avoid disruption to sources already 

subject to the mass-based trading federal plan, the EPA is not 

proposing to allow allowance borrowing across compliance 

periods. 
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Although not proposing to provide for allowance borrowing 

across compliance periods, the agency requests comment on the 

potential inclusion of allowance borrowing in the proposed massbased trading federal plans, including from how far into the 

future to allow allowances to be borrowed, how inclusion of 

borrowing would affect opportunities for states to take over 

implementation of the EGs (or implementation of the allowancedistribution provisions in the mass-based trading federal plan), 

how to address removing the extra allowances from circulation 

that would result if borrowed allowances originate in a state 

that subsequently withdraws from the mass-based trading program, 

and on other complexities that borrowing across compliance 

periods would introduce. 

The agency proposes to require sources to demonstrate 

compliance, i.e., allowance true-up, on May 1 of the year after 

the last year in the compliance period. For example, if the 

first compliance period comprises the three years 2022, 2023, 

and 2024, then the allowance transfer deadline87 for that first 

compliance period (after which point the EPA would evaluate 

 

87 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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compliance) would be on May 1, 2025. The agency also requests 

comment on an earlier or later allowance transfer deadline. 

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

true-up) at the facility level, not at the individual affectedEGU level, in the mass-based trading program. Facility-level 

compliance may ease implementation compared to unit-level 

compliance; each facility has a single compliance account in 

which to hold allowances to cover emissions from all its 

affected EGUs rather than having individual unit-level 

compliance accounts. Fewer accounts may make it easier for the 

designated representatives to manage their allowances. The EPA 

has adopted facility-level compliance in previous emissions 

budget-trading programs including the Acid Rain Program (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 
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can take into account a wide range of considerations and tailor 

decisions to the particular characteristics and preferences of 

their state. We are proposing that states have the flexibility 

to determine their own approach for distributing allowances in 

the federal plan, through a process that is detailed in section 

V.E of this preamble. The EPA believes that states should have 

the opportunity to make decisions about allowance distribution 

and that they may have additional flexibility on approaches, 

including allowance auctions. The EPA is also proposing an 

allocation approach that we intend to use in the event we 

implement the federal plan in a state that does not choose to 

determine its own allowance-distribution approach. The EPA is 

requesting comment on all of these, and any other, approaches to 

distribute allowances. 

The initial allowance allocation approach that is based on 

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 
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with the flexibility to buy, sell, or bank allowances. Allowance 

allocation is simply a procedure by which allowances are 

distributed into the marketplace so that they may be available 

for affected EGUs to acquire as desired to authorize emissions 

under the program. However, because these allowances are finite 

in number and thus a limited resource, they have value, and as a 

result, initial allowance allocations may raise issues of equity 

among recipients. 

Thus the agency recognizes that its choice of allocation 

methodology is important from the perspective of distributional 

effects, and the importance of selecting an approach that is 

fair and reasonable in light of this consideration and the 

overall purpose of CAA section 111 informs the agency’s thinking 

in this proposal. We also invite comment on these 

considerations, and on any other factors or considerations which 

commenters believe should inform the allocation method. 

The EPA believes that the most reasonable basis for an 

initial allowance allocation procedure is an approach that uses 

historical data reported by the affected EGUs subject to the 

requirement to hold allowances under this program. This approach 

relies on known data rather than future projections. The EPA 

believes this approach is preferable because any approach tied 

to future indicators (e.g., the expected future EGU-level 
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pattern of emissions or the ultimate use of allowances) would 

depend on future outcomes that the EPA cannot project with 

perfect certainty in advance. Basing allocation on 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 

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. 
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Although the EPA cannot anticipate the future EGU-level 

pattern of emissions, it is possible to consider potential 

future emission patterns at the source subcategory level. In 

developing the Clean Power Plan EGs, the agency conducted 

analysis of emission reduction potential in the two affected EGU 

source subcategories, i.e., electric utility steam generating 

units (steam generating units) and NGCC units. With that 

analysis as a basis, the EPA is requesting comment on an 

alternative allocation approach that would first divide the 

total number of allowances from each state’s mass goal into 

source subcategories based on analysis done in developing the 

source category-specific CO2 emissions performance rates 

promulgated in the EGs and then allocate to affected EGUs within 

each category based on shares of historic generation. This 

alternative is described later in this section. 

The EPA recognizes that states may prefer different

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 
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EPA is not proposing here, provided that the state’s approach 

addresses emissions leakage through an allowance allocation 

strategy, such as the one detailed in section V.E of this 

preamble88, and includes a Clean Energy Incentive Program as 

detailed later in this section. It is the agency’s intention 

that states electing to submit a state allowance-distribution 

methodology under the federal plan will have the flexibility to 

determine whether to include a set-aside and how such a setaside will be distributed if they choose to submit a state 

allowance-distribution methodology. The EPA proposes that a 

state could choose its own method for distributing allowances 

for any compliance period including the first period that would 

commence in 2022. The proposed process for a state to replace 

federal-plan allowance-distribution provisions with its own 

allowance-distribution provisions is detailed in section V.E of 

this preamble. 

The following sections discuss and request comment on the 

 

88 The state can adopt an allowance allocation strategy to address leakage, or 

they may alternatively make the justification that leakage is already 

addressed by existing jurisdiction policy, by unique characteristics of the 

jurisdiction or by some other aspect of their state plan. This justification 

must be supported by credible analysis. See section V.D.3 below for more 

information on the requirement to address leakage. Further information is 

also available in the final EGs sections VII.D. and VIII.J. 
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EPA’s proposed approach to allocate CO2 allowances to affected 

EGUs based on shares of historic generation, the proposed timing 

of allowance recordation, three proposed allowance set-asides, 

allocations to units that change status, and the proposed 

approach for states to replace federal-plan allocation 

provisions with their own allowance-distribution approaches. In 

addition, we request comment on alternative allowance 

distribution approaches – such as auctioning or allocations to 

load-serving entities – that the EPA or states might adopt. The 

EPA requests comment on all of these aspects of allowance 

distribution. 

1. Proposed Allocation Approach and Alternatives 

The EPA proposes to allocate most of the CO2 allowances in 

the mass-based trading program to affected EGUs based on 

historic generation (output) data. The EPA also proposes three 

allowance set-asides. The first would set aside a portion of 

allowances in each state from the first compliance period only; 

this set-aside is for a proposed Clean Energy Incentive Program 

that is detailed in section V.D.4 of this preamble. The second 

would set aside a portion of allowances in each compliance 

period except for the first period; theEPA proposes to 

distribute allowances from this set-aside to affected EGUs via 

an updating output-based approach as detailed in section V.D.3 
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of this preamble). The third would set aside five percent of 

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

distributed to renewable energy projects as detailed in section 

V.D.3 of this preamble. In summary, the proposed set-asides 

include: 

(1) Clean Energy Incentive Program. This set-aside would be 

of first compliance period allowances only. 

(2) Output-based allocation set-aside. This set-aside would 

start in the second compliance period and continue for each 

compliance period. 

(3) Renewable energy set-aside. This set-aside would be 

implemented in all compliance periods. 

This section describes the proposed historic-generationbased approach that the agency would use to allocate all 

allowances except for the set-aside allowances. The EPA is 

proposing affected-EGU-level allocations (based on available 

data) in every state. Further detail on this proposed allocation 

approach is provided in the Allowance Allocation Proposed Rule 

TSD in the docket. The affected-EGU-level allocations resulting 

from this proposed historic-generation-based approach are 
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provided in the docket in an appendix to the TSD. The agency 

requests comment on the proposed historic-generation based 

allocation approach and on other allocation approaches. 

The EPA proposes to allocate the historic-generation-based 

portion of the allowances (i.e., the mass goal minus the setasides89) to individual affected EGUs based on each affected 

EGU’s share of the state’s historic generation, using 2010 

through 2012 data. The calculation steps for this proposed 

historic-generation–based allocation approach are as follows: 

1. For each unit in the list of likely affected EGUs in each 

state, identify annual net generation values for the 

historic period of 2010 through 2012 (reflecting affectedEGU-specific generation assumptions incorporated in the 

data adjustments, e.g., assumed capacity factor for “under 

construction” units). For a year for which an affected EGU 

has no generation data (e.g., a year before the year when a 

unit started operating), assign the affected EGU a value of 

 

89 In the first compliance period this would be the mass goal minus 

the Clean Energy Incentive Program set-aside and the RE set-aside. 

In all other compliance periods this would be the mass goal minus 

the output-based allocation set-aside and the RE set-aside. 
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zero.90 (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 

 

90 The EPA proposes that for affected EGUs that were under 

construction and began operation during 2012 or after 2012 (and 

thus don’t have a full year of generation data from the 2010 

through 2012 period), the allocation calculations be based on the 

same 2012 generation estimate as the agency used in the Clean Power 

Plan EGs for the goal-setting calculations. That is, the EPA 

proposes to estimate 2012 generation for such units based on a 

unit’s net summer capacity and assuming a 55 percent capacity 

factor for gas units and a 60 percent capacity factor for steam 

units. 
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inform unit-level initial allocations in order to consider 

a broader range of unit-specific operations over time. 

2. Determine each affected EGU’s average generation value by 

averaging all (non-zero) 2010 through 2012 annual 

generation values for the unit. The proposed approach would 

use only non-zero values in calculating a unit’s average 

generation. For example, if generation data for a unit were 

available for only 2011 and 2012 then the EPA would only 

use the 2011 and 2012 values to determine the unit’s 

unadjusted average generation value. The EPA included 

generation from all units in the historic data set in the 

proposed allowance calculations and calculated allowances 

for all such units; the agency requests comment on the 

treatment of generation from and allocations to units that 

operated in the historic data set but retire before the 

start of the program. 

3. In each state, sum the average generation values from all 

affected EGUs to obtain that state’s “total average

historic generation.” 

4. Divide each affected EGU’s average generation value by the 

state’s total average historic generation to determine that 
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affected EGU’s share of the state’s total average historic 

generation. 

5. Multiply each affected EGU’s share of the state’s total 

average historic generation by the historic-generationallocation portion of the state’s mass goal (i.e., the 

state’s mass goal minus the set-asides) to determine that 

affected EGU’s allocation. 

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

reasons: 

• The agency believes that the proposed historicgeneration-based approach maximizes transparency and 

clarity of allowance allocations. The EPA has placed in 

the docket the historic generation data and the 

calculations used to determine the proposed affected-EGUlevel allocations. The agency also placed the proposed 

affected-EGU-level allocations, resulting from these 

calculations, into the docket. These calculations can be 

relatively easily replicated. 

• To calculate allocations, the EPA proposes to use 
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historic affected-EGU-level net generation data compiled 

using a methodology similar to the Emissions & Generation 

Resource Integrated Database (eGRID) methodology. The 

proposed calculation approach is described further below 

and in the Allowance Allocation Proposed Rule TSD in the 

docket. The historic-data methodology is described in the 

CO2 Emission Performance Rate and Goal Computation TSD

for CPP Final Rule. The majority of the generation-unitlevel data in this approach are from reports that 

emissions sources submit to the EPA under 40 CFR part 75 

and to the 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 Acid 

Rain Program, and the CSAPR, based on historic data. For all 

these reasons, the agency believes that it is appropriate to use 
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a historic-generation-based allocation methodology in this 

proposed rule. The EPA also requests comment on a historic-data 

approach based on historic emissions. 

The proposed historic-data-based allocations approach would 

not generally affect the ultimate pattern of generation across 

individual power plants, as compared to other methods of 

allocation. The combination of plants, and their contributing 

generation, that will be used to meet a particular demand for 

electric power will be based on the relative efficiency (cost of 

production) of available plants. The relevant measure of this 

efficiency is the marginal cost of generation, which for a 

particular power plant would be the sum of the cost of 

additional fuel to generate an additional MWh, additional 

maintenance costs to increase output by an additional MWh, and 

costs associated with the additional emissions that result from 

generating an additional MWh. In a mass-based trading program, 

additional emissions must be covered by additional allowances, 

so the cost of emitting is the price of the allowances that must 

be consumed to authorize those emissions. These emissionsrelated costs of electricity production are the same regardless 

of whether the allowances used to cover those emissions were 

initially allocated to the user or whether they were acquired 

subsequently in the marketplace. 
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The same concept applies to any other cost of electricity 

production. For example, a coal-fired 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 

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 
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plants. While cost-of-service markets are structured differently 

from competitive markets, the regulated utility still makes the 

dispatch decision on the basis of marginal costs among the units 

in its fleet, which is not affected by the amount of allowances 

that any particular unit in that fleet was initially allocated 

(assuming a competitive allowance market). 

The EPA recognizes that some stakeholders are concerned 

about the potential future distribution of emissions at the 

facility level, and possible effects on communities. However, 

for the reasons discussed in the above paragraphs, allowance 

allocations that do not change based on future activity (such as 

allocations under the proposed historic-generation based 

approach) do not affect the distribution of emissions under the 

program. This proposed rule is expected to achieve significant 

emission reductions across the electric power sector; see 

section IX of this preamble for discussion of anticipated broad 

benefits to communities. 

In addition to the proposed historic-data-based allocations 

approach, the EPA also requests comment on other allocation 

approaches. One alternative approach on which the agency 

requests comment is similar to the proposed approach in that it 

allocates allowances based on historic generation. However, this 

alternative approach would divide the total number of allowances 
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from a state’s mass goal (minus the set-asides) into affected 

EGU source categories – based on analysis done in developing the 

source category-specific CO2 emissions performance rates 

promulgated in the Clean Power Plan EGs – before determining 

unit-level allocations. The EPA requests comment on this 

alternative approach because dividing the allowances in a state 

by source category in this manner may result in an initial 

distribution of allowances that would be closer at the sourcecategory level to the future category-level pattern of 

emissions, and thus to allowances ultimately used, than the 

proposed approach. To the extent that this category-level 

division of allowances is a reasonable proxy for the future 

category-level emissions pattern under the program, this 

approach may reduce wealth transfer between parties that occurs 

as a consequence of a less-anticipatory initial allocation 

procedure. The EPA cannot observe in advance the future 

affected-EGU-level pattern of emissions. 

In this alternative approach, for each state the EPA would 

multiply historic steam-generating-unit generation by the steamgenerating-unit source category-specific CO2 emissions 

performance rate, and multiply historic NGCC-unit generation by 

the NGCC-unit source category-specific CO2 emissions performance 

rate. The EPA would do these calculations for each of the 
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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 8 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 

calculation. The EPA would then allocate the steam–generatingunit portion of the allowances to individual steam generating 

units 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 historicgeneration 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. 
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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.91 Alternatively, 

allocations could be distributed based on projected or observed 

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

The proposed and alternative allocation approaches would 

determine most of the allocations before the start of the 

program. Other potential allocation approaches would change 

allocations for future compliance periods based on future 

activity – referred to as “updating” allocations. This proposed 

rule includes an updating-allocation component, as we are 

proposing to set aside a portion of the allowances in each state 

for distribution using an updating output-based approach as 

detailed in section V.D.3 of this preamble. The EPA requests 

comment on the use of other updating allocation approaches. 

Another allowance allocation approach that could minimize 

 

91 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 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 lowincome 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.92 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 

 

92 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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agency requests comment on the idea of auctioning all, or a 

portion of, each state’s allowances in the proposed federal 

plan, on how much of each state’s allowances to auction if not 

the entire amount, on the frequency (e.g., yearly or every few 

years), design of auctions (e.g., spot or advance; first, 

second-price or other) and who may participate in the auction. 

The EPA requests comment on an alternative approach, which 

is allocating a portion of the allowances to load-serving 

entities (LSEs) rather than to affected EGUs. LSEs are the 

entities responsible for delivering power to retail consumers. 

Allocation to LSEs can help mitigate bill impacts on 

electricity consumers when applied in concert with certain 

additional design features. In particular, if LSEs commit and/or 

are required to pass through to ratepayers the value from their 

selling of the allocated allowances, this approach can mitigate 

the impact of electricity bill increases on consumers that might 

otherwise result from application of the federal plan. As 

described in the Allowance Allocation TSD, this type of approach 

can also help to avoid or mitigate the potential for windfall 

profits for affected EGUs. The EPA could apply this approach by 

conditioning the receipt of allowances by LSEs on the pass 

through to consumers of any allowance value if necessary. 

The EPA requests comment on the design and utility of 
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allocating allowances to LSEs to help mitigate electricity price 

impacts. In particular, the EPA requests comment on options to 

establish conditions requiring pass through of allowance value 

and verification of such pass-through, whether it would be 

appropriate to identify any conditions related to equitable 

distribution of allowance value among ratepayer categories, as 

well as the EPA’s legal authority to apply any such conditions. 

The EPA requests comment on the additional design aspects 

of any potential allocation to LSEs, including but not limited 

to the following questions: In particular, what metric should 

provide the basis for LSE allocation, e.g., electricity demand 

served by the LSE, population served by the LSE, emissions 

associated with generation serving the LSE, or some other 

metric. If emissions are used as the basis for such allocation, 

what approach should be taken: on a historic basis or a 

continually updated basis, on the basis of estimated emissions 

for the relevant region or some other basis, and using what data 

to calculate such emissions. Also, the EPA requests comment on 

the form by which LSEs may distribute the allowance value to 

rate-payers, e.g. as a fixed amount, through reduced rates, etc. 

Finally, the EPA requests comment on what share of the total 

number of allowances should be distributed to LSEs and what 

monitoring and reporting requirements may be necessary to 
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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 

agency also requests comment on the proposed allowance setasides, which are detailed below. The agency requests comment on 

allocation approaches that may minimize the impact of this 

proposed rule on small entities. The EPA also requests comment 

on any other approaches to distribute allowances. Finally, the 

agency notes that we propose to provide that any state may 

choose to replace the federal-plan allocation provisions with an 

allocation approach of its choosing as discussed below. 

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 
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accounts prior to the start of each compliance period, and to 

record allowances for one compliance period at a time. Recording 

allowances prior to the start of a compliance period provides 

certainty to affected EGUs of their allocations in advance of 

when the allowances are needed for compliance and can facilitate 

long-term planning. Recording allowances for one compliance 

period at a time provides flexibility for a state to replace the 

federal plan with its own plan in a timely way. As discussed in 

section V.F of this preamble, the EPA proposes to allow a state 

to replace the federal plan with its own approved state plan, 

for a compliance period for which allowances have not yet been 

recorded (the proposed schedule for allowance recordation is 

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

to replace the federal-plan allocations to its affected EGUs 

(and other entities) with its own allocations approach, for a 

compliance period for which allowances have not yet been 

recorded as detailed in section V.E of this preamble. 

The agency proposes to record allowances for the mass-based 

trading program in accounts of affected EGUs seven months prior 

to the start of each compliance period. For example, if 

compliance periods are 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 
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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 

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.93

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 (e.g., the 

rate-based and mass-based state goals) to create a larger 

incentive for new fossil fuel-fired sources to generate compared 

 

93 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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to implementation in the form of subcategory-specific emission 

performance rates.. The final EGs specified that mass-based plan 

approaches must address leakage, because the nature of the mass 

goals would create differing incentives to run affected existing 

EGUs and for new sources, which could result in new sources 

running more and producing more emissions. These circumstances 

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

approach, where both affected EGUs and new sources face similar 

incentives to run. By requiring plan components that address 

leakage, the final EGs ensure that mass goals are an equivalent 

alternative to the subcategory CO2 performance rates and the 

rate-based state goals. 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 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 

set-aside provisions exactly as they are outlined in this model 

rule once it is finalized, the requirement for that state plan 
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to address leakage would be considered presumptively approvable. 

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

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

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

the allowance allocation alternative for addressing leakage must 

be chosen for the federal plan and model rule proposal instead 

of the option to regulate new non-affected fossil fuel-fired 

EGUs. This is because the EPA does not have authority to extend 

regulation of and federal enforceability to new fossil 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.94 The EPA believes these set-aside programs are 

 

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

recognizes its authority as being, in some sense, the same as that 
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both authorized and consistent with the purpose of the Clean 

Power Plan under CAA section 111(d) and the specific 

requirements specified in the final guidelines. They do not have 

the effect of increasing the stringency of the federal plan 

because the overall budget of allowances (representing allowable 

emissions) remains the same. 

The EPA is aware of the successful use of set-asides and 

similar programs in other emissions trading programs. The 

following are examples of set-asides and similar programs used 

in other federal air quality rules, and in state-based GHG 

regulatory programs. 

The EPA has previously established set-asides of emissions 

allowances in FIPs under CAA section 110. For example, in the 

Cross State Air Pollution Rule (CSAPR), the EPA used a 5 percent 

set-aside for new units, because we believed it was “important 

to have a small new unit set-aside in each state to cover new 

units within the budget that was set aside in order to address 

the state’s significant contribution and interference with 

maintenance.” (75 FR 45310; Aug. 2, 2010). This was important, 

in the EPA’s view, because it allowed for growth in the electric 

 

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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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.95 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 setaside, the EPA chose the latter. 

As part of the Acid Rain Program 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 

 

95 See also EPA, Allowance Allocation Final Rule TSD, EPA-HQ-OAR2009-0491, at 3-4 (June 2011). 
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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.”96 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 EE and renewables as a strategy in meeting their 

[emission] budgets. One way to achieve this goal is including a 

provision with a state’s NOx Budget Trading Rule that allocates a 

portion of a state’s trading program budget to implementers of 

EE 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 setasides 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 

 

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

Reserve, EPA 430-R-94-010 (Nov. 1994). 
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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.97 In general, the EPA 

believes its experience and those of the states with these setaside programs support the view that they are an effective means 

to spur clean energy projects, which in turn we believe can help 

to reduce the risk of leakage in this instance.98

 

97 U.S. EPA, State Clean Energy-Environment Technical Forum 

Roundtable on State NOx Allowance EE/RE Set Aside Programs, Call 

Summary (June 6, 2006), available at 

http://www.epa.gov/statelocalclimate/documents/pdf/summary_paper_nox_allowan

ce_6-6-2006.pdf. 

98 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_setasides_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_setasides_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_setasides_vol3.pdf.
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Below, the EPA describes two potential allowance setasides. First, the EPA proposes a set-aside for allowances 

distributed to existing NGCC units based on output (i.e.,

output-based allocation) to mitigate emission leakage to new 

sources. 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, 

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 
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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 

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 
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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 

emissions guidelines 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., 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 
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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 steam generating 

units. Output-based allocation for steam generating units may 

increase generation subject to the mass limit, leading to 

reduced generation and emissions from new emitting sources. 

However, the EPA does not propose this approach because it is 

not as effective as output-based allocation to NGCC units. This 

is because output-based allocation to steam generating units 

would incentivize generation from relatively high-emitting EGUs, 

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 zeroemitting generators. 

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 
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factor on a net basis over the compliance period, and only for 

the portion of their generation that exceeds that capacity 

factor.99 

The EPA also solicits comment on the timing of the OBA setaside’s allocation procedure, which involves the relationship 

between the time at which eligible generation occurs and the 

vintage year(s) of the allowances allocated from this set-aside 

to recognize that generation. The EPA is proposing a lagged 

accounting procedure for this set-aside, where eligible 

generation that occurs during a given compliance period would 

receive allowances through this set-aside taken from vintage 

years in the subsequent compliance period. In keeping with this 

lagged accounting procedure, the EPA is proposing not to reserve 

any allowances of vintage years during the first compliance 

period (2022-2024) for allocation through this set-aside; 

eligible generation that occurs during the first compliance 

period would be recognized through this set-aside with 

allowances of vintage years from the second compliance period 

(2025-2027). 

The EPA is proposing this lagged accounting procedure 

because the amount and location of eligible generation in any 

 

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

allocation is zero up until this average capacity factor. 
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given compliance period remains uncertain until the compliance 

period has ended and the relevant data has been reported and 

verified. Without this lagged accounting procedure, the EPA 

would have to withhold an amount of allowances for this setaside from certain vintage years even as the corresponding 

compliance period was already underway. Given the size of this 

proposed OBA set-aside in certain states, the EPA believes it 

would be more advantageous for affected EGUs to know in advance 

how many allowances they will be allocated in a given period, 

inclusive of allowances allocated through this OBA set-aside.100 

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 

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 

 

100 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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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 lb/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.101

The EPA proposes to use net summer capacity as reported to EIA. 

In the alternative, the EPA proposes to require that NGCC units 

report net summer capacity directly to the EPA by adding it as 

 

101 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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a required data field in the certificate of registration that a 

unit’s owner or operator would submit to the agency (see section 

V.G 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 
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the allowances in a given compliance period to be allocated 

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.102 The EPA would calculate the size of the set-aside as 10 

percent of the NGCC capacity in the state103 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 set-

 

102 CO2 Emission Performance Rate and Goal Computation TSD for the 

CPP Final Rule.

103 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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aside. Although the size of the set-aside would remain the same 

for each compliance period, as the mass goals decrease with each 

step in the Interim Period and to the Final Period, the 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
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Lands of the Navajo Nation 0

Lands of the Uintah and Ouray Reservation 0

Louisiana 2,207,879

Maine 563,925

Maryland 103,762

Massachusetts 2,439,991

Michigan 2,105,786

Minnesota 909,724

Mississippi 3,132,671

Missouri 815,210

Montana 0

Nebraska 144,635

Nevada 2,326,529

New Hampshire 542,721

New Jersey 3,413,100

New Mexico 627,085

New York 3,815,381

North Carolina 2,120,178

North Dakota 0

Ohio 1,757,326

Oklahoma 3,121,167

Oregon 1,291,027

Pennsylvania 4,392,931

Rhode Island 778,307

South Carolina 1,029,366

South Dakota 130,831

Tennessee 632,949

Texas 15,990,657

Utah 825,586

Virginia 3,011,811

Washington 1,383,060

West Virginia 0

Wisconsin 1,181,175

Wyoming 45,114

 

Given the proposed limit on the total size of the setaside, and the amount of potential generation eligible for the 
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set aside, there may be fewer allowances available in the set 

aside than can be earned at the allocation rate. The EPA 

proposes that, if the amount of total generation eligible for 

the set aside multiplied by the allocation rate exceeds the size 

of this set-aside, then the allowances in this set-aside would 

be allocated to eligible generation on a pro-rata basis. 

The EPA proposes that if the number of allowances allocated 

from the set aside is less than the size of this set-aside, then 

the remaining allowances would be distributed to all affected 

EGUs using the historic-generation based-approach described 

above. 

The EPA proposes to provide notice of the capacity and 

generation data used to calculate allocations from the setaside, and the resulting allocations, by August 1 of the first 

year in each compliance period, e.g., by August 1, 2025 for the 

compliance period that commences in 2025 (and based on the data 

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. 
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The EPA requests comment on all aspects of the proposed 

approach to calculate output-based set-aside allocations. 

Further details are in the Allowance Allocation Proposed Rule 

TSD in the docket. 

b. Set-asides for Renewable Energy Projects 

The EPA proposes to provide a set-aside of allowances for 

distribution to renewable energy (RE) in each state covered by 

the proposed mass-based federal plan. The agency is also taking 

comment on whether distribution should extend to demand-side 

energy efficiency (DS-EE) and combined heat and power (CHP) 

projects. Under this program, the EPA would reserve a percentage 

of each state’s allowances in a set-aside account for each 

state. Developers of RE projects could apply to receive setaside 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 
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proposed mass-based trading program itself would provide 

incentive for new and existing low and zero-emitting generation. 

 The EPA is proposing that a unique set-aside would be 

created for each state covered by a mass-based federal plan. The 

allowances in each set-aside would be reserved from each vintage 

of the assigned mass goal to that state prior to allocation of 

allowances to sources. The EPA is proposing that five percent of 

allowances will be reserved 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 
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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 that a project is eligible to receive setaside allowances if it is renewable energy (RE) that meets the 

eligibility requirements for rate-based ERC issuance as 

specified in section IV.C of this 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 Acid Rain 

Program 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. 

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 
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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. 

Specifically, the following RE measures are eligible: on-shore 

wind, solar photovoltaics (PV), concentrated solar power, 

geothermal power, and hydropower. The RE measure must also have 

the capacity to provide data quantified by a revenue-quality 

meter, as described in the eligibility requirements for ratebased ERC Issuance in section IV.F.2 of this preamble, above. 

New nuclear units and capacity uprates at existing nuclear units 

are not proposed to be eligible to receive set-aside allowances, 

as we do not think a set-aside used as an incentive for 

incremental nuclear capacity is a useful way to address leakage 

to new sources during the performance period, due to unique 

costs and development timelines for incremental nuclear power. 

All other proposed aspects of the eligible measure types 

described in section IV. C of this preamble and the requests for 

comment included within that section also apply in the massbased set-aside context. For example, we are requesting comment 
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on the inclusion of other RE measures, incremental nuclear, 

demand-side EE measures, CHP and any other technologies as 

eligible measures to receive set-aside allowances. We 

particularly request comment on how a set-aside to provide an 

incentive from these particular measures will serve to address 

leakage to new sources. We also request comment on the 

implications of the inclusion of such technologies for the 

streamlined implementation of projection-based EM&V requirements 

of the set-aside specified below in a federal plan context 

across the applicable jurisdictions, while still maintaining 

necessary rigor. We request comment on the appropriateness of 

the biomass eligibility options offered in section IV.F.2 of 

this preamble in a mass-based set-aside context to address 

leakage. We also request comment on appropriate processes 

through which 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, 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 
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question, and a projection of expected annual megawatt-hour 

generation for an RE project. The EPA must approve the 

documentation of eligibility and the projection of megawatthours before the project becomes eligible for a distribution of 

the set-aside allowances. In addition, the proponent must 

register for a general account in the EPA tracking system where 

the allowances would be recorded. See 40 CFR 62.16320 for the 

requirements to establish a general account. While the EPA is 

proposing to allow eligible resources to use a general account 

to receive any allowances allocated 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. 

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 
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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 

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 
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because the ultimate amount of allowable CO2 emissions is 

determined by the total number of allowances initially created 

(regardless of how they are distributed). As a result, while the 

EPA believes it is reasonable to consider a minimum set of 

qualifications for recognizing RE through these allowance setasides to assure that the RE generation that is incented is 

actually produced, the EPA does not believe the overall 

integrity of mass-based implementation is significantly affected 

by the robustness of whatever eligibility requirements the EPA 

ultimately sets for RE recognition through allocation from these 

set-asides. This being said, the agency is proposing to require 

robust demonstrations of the eligibility and EM&V projections 

for RE generation submitted for the set-aside, demonstrations 

that are based in the best practices of existing programs. This 

is necessary to assure the delivery of RE as a result of the 

set-aside. 

The EPA proposes that the projections of megawatt-hours 

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 
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methods, assumptions and data sources must be specified in 

documentation accompanying the projections. These projections 

and supporting documentation should all be provided in the setaside project application, and that application must be approved 

by a third-party verifier. The EPA invites comment on these 

proposed requirements for projections. We also take comment on 

whether set-asides should be distributed proportional to actual 

megawatt-hours 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. 

The EPA is proposing the following process for distribution 

of RE set-aside allowances. Starting prior to the compliance 

period, and going forward through the compliance period, RE 

providers in each state will have an opportunity to apply to the 

EPA or a designated agent to be approved as eligible to receive 

set-aside allowances in their state. This application must 

include all the requirements outlined above, including 

projections of expected megawatt-hours 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 
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will be entered into the pool of projects that will receive setasides in any compliance period. If approved, the number of 

projected megawatt-hours in each generation year will be the 

basis of the number of allowances the provider will receive, as 

an input to the methodology specified below. The providers will 

have an opportunity to update projections for future generation 

years, these projections must be received by June 1 of the year 

prior to the generation year in question. 

On December 1 of the year prior to each year of the

compliance period in question, the EPA is proposing to 

distribute allowances from the set-aside to approved providers. 

The agency is proposing to distribute set-aside allowances to 

approved RE providers pro-rata, with the number of allowances 

distributed to each provider according to the percentage of 

total approved RE megawatt-hours for that state that the 

approved MWHs from their project represent. This method is 

proposed because it treats all eligible RE projects equally in 

the distribution of set-aside allowance. It also inherently 

provides a more significant incentive in states with less 

eligible RE generation, but will become less significant as RE 

generation increases. We would also like to take comment on 

whether to restrict projects to a maximum number of allowances 

they can receive per megawatt-hour of generation, such as 1 
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allowance per megawatt-hour. 

After each generation year, RE providers receiving 

allowances will have to provide an M&V report with the megawatthours of RE generation actually produced, to assure that they 

have met the projected level of generation. These M&V reports 

need to document that the generation was by an approved project, 

and the report should be approved by a third party verifier. As 

discussed in the rate-based approach EM&V section above, these 

data should be readily available from existing metering. The EPA 

requests comment on the process for submitting M&V reports with 

actual generation. 

If the project or program does not reach the megawatt-hours 

projected in a particular generation year, the unfulfilled 

megawatt-hours will be subtracted from that RE provider’s 

megawatt-hours eligible for the set-aside in the next generation 

year, or multiple years if the deficit exceeds the MWhs 

projected for the upcoming year. If this deficit is greater than 

10 percent in a particular year, the provider will need to 

provide an explanation of the deficit and will be required to 

reevaluate their projections for future years. If such deficits 

continue through all three years of the any performance period 

in which they participate, the provider will be disqualified 

from receiving future set-asides for the following compliance 
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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 

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. 

The EPA is also seeking comment 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 
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much of the set-aside should be designated as targeted at lowincome communities. We also request comment on whether the 

methods of approval and distribution of allowances to projects 

that benefit low-income communities should differ from the 

methods that are proposed to apply to other RE projects. 

The EPA seeks comment on all aspects of this proposed RE 

allowance set-aside program, including whether it should be 

included as part of a mass-based federal plan, the structure of 

the set-aside reserve, eligibility requirements for receiving 

set-aside allowances, demonstration of eligibility, and the 

process for distribution of allowances. 

4. Provisions to Encourage Early Action 

For purposes of the proposed mass-based federal plan, the EPA 

proposes to implement the Clean Energy Incentive Program (CEIP) by 

issuing early action allowances for actions that reduce or avoid 

CO2 emissions in 2020 and 2021. These early action allowances would 

be drawn from a third set-aside of allowances from the general 

distribution methodology. The EPA believes it is reasonable to 

establish the total amount of the early action-set aside in an 

amount equal to the pool of matching allowances. Thus, the EPA 

proposes that the total early action set-aside would be of an 

amount equal to the pool of matching allowances: no more than 300 

million CO2 allowances, depending on how many states are subject 
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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.104 See Table 10 of this preamble for the proposed set-asides 

for each state under the mass-based federal plan. The agency 

proposes to set aside 100 million early action allowances from 

each of the three years in the first compliance period (2022, 2023, 

and 2024) for a total of 300 million allowances to be set aside. 

While the table shows set-asides for every state, the EPA proposes 

to implement this set aside, according to the amounts listed in 

Table 10, only for those states for whom the EPA is implementing 

the mass-based federal plan. The EPA also requests comment on other 

approaches to determining the size of this set-aside in the massbased federal plan. 

 

104 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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In accordance with the final emission guidelines, the EPA is 

proposing to award early action allowances to two types of eligible 

projects located in or benefitting the state for which the EPA is 

implementing a federal plan: 

• RE investments that generate metered MWh from wind or solar 

resources; and 

• Demand-side EE programs and measures that result in

quantified and verified avoided generation, and demonstrate 

a direct benefit to low-income communities. 

 The EPA proposes the following framework to implement the CEIP 

in the mass-based federal plan. First, the EPA proposes to create 

a set-aside of early action allowances for all federal-plan states, 

as described above. Second, the agency proposes to create an 

account of matching allowances for each state participating in the 

CEIP – regardless of whether a state is implementing a state plan 

or the agency is implementing a federal plan on its behalf. This 

distribution would reflect each state’s pro rata share of a federal 

pool of additional allowances, which will be limited to the 

equivalent of 300 million short tons of CO2 emissions. The matching 

allowances would be distributed to all participating states based 

upon the amount of the reductions from 2012 levels each state must 

achieve relative to that of the other participating states. Thus, 

states whose EGUs face greater reduction obligations would be 
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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 realized in 2020 and 2021. The EPA also 

seeks comment on whether the number of matching allowances 

available to a state under the 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 allowance set-aside 

account. 

The EPA proposes to execute an initial distribution of matching 

allowances following receipt of 2016 state submittals, and a final 

distribution following receipt of all complete state plans in 2018, 

by which time the EPA may also have issued federal plans for some 

states. 

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 2021: 

• For RE projects that generate metered MWh from 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 
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number of matching allowances equivalent to one MWh from 

the EPA. 

• For EE projects that benefit 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, including the 

appropriate factor for determining equivalence between allowances 

and MWh, 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. All matching allowances that have 

not been used by January 1, 2023 would be retired by the EPA. The 

EPA proposes to distribute any remaining early action set-aside 

allowances in a state – after distribution to all eligible projects 

in the state – to the affected EGUs in the state on a pro-rata 

basis in proportion to the initial allocations made to those EGUs 

under the mass-based federal plan. 

As discussed in section V.E of this preamble below, the EPA 

proposes to allow any state where a federal plan is being 

implemented to take responsibility for distributing allowances to 
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affected sources. This will allow a state to tailor its allowancedistribution approach to the characteristics and preferences of 

the state. The EPA proposes that for approval of a delegation or 

a partial state plan to handle allocations, a state that chooses 

to replace the federal-plan allocations with a state-determined 

approach must include a CEIP set-aside, as authorized in section 

VIII.B.2 of the final EGs. The EPA intends that such a state would 

have the same flexibilities as a state implementing a full state 

plan with respect to implementation of the CEIP. That is, the state 

would not be required to implement a set-aside of the same size as 

proposed in Table 10 of this preamble, but rather could choose how 

many of its allowances to set-aside for the CEIP. 

The EPA requests comment on all aspects of implementing the 

CEIP under a mass-based federal plan approach, including (1) The 

size of the early action allowance set aside; (2) the approach for 

distributing the early action allowance set-aside among states; 

(3) the timing of distribution of set-aside and matching 

allowances; (4) the amount of allowances awarded per eligible MWh 

generated or avoided; (5) the criteria for eligible projects, 

including criteria for awards to EE projects that benefit lowincome communities; (6) the mechanism for reviewing project 

submittals and issuing early action allowances; and (7) EM&V 

requirements for eligible projects. The EPA also seeks comment on 
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how states, tribes and territories for whom goals have not yet 

been established in the final emission guidelines 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. In 

addition, the EPA requests comment on not providing matching 

allowances in the mass-based trading federal plan, or on only 

providing matching allowances in federal plan states that choose 

to determine their own allocation approach. 

Table 10. Proposed Clean Energy Incentive Program Early Action 

Set-Aside in Mass-Based Federal Plan for Projects in 2020 and 2021 

(Short Tons) 

State 

Set-Aside 2022 

through 2024 

Alabama 3,122,306

Arizona 1,719,618

Arkansas 2,187,230

California 218,846

Colorado 2,223,192

Connecticut 69,415

Delaware 138,392

Florida 3,230,248

Georgia 2,755,623

Idaho 14,929
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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
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Texas 10,400,192

Utah 1,401,189

Virginia 1,386,546

Washington 751,434

West Virginia 3,506,890

Wisconsin 2,393,870

Wyoming 3,104,324

5. Allocations to Units that Change Status 

Units that retire. The EPA proposes that, if an affected 

EGU does not operate for two consecutive calendar years, the 

unit would continue to receive allocations for a limited number 

of years after it ceases operation, after which the allowances 

that would otherwise have been allocated to that unit would be 

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

which the retired unit is located.105 Continuing allocations to 

non-operating units for a period of time reduces the incentive 

to keep a unit operating simply to avoid losing the allowance 

allocations for that unit (e.g., a unit that would otherwise be 

retired due to age and inefficiency). On the other hand, nonoperating units are no longer emitting and so do not need 

 

105 This is similar to the approach taken in CSAPR of continuing 

allocations to retired units for four years and then allocating 

the allowances to a set-aside; in CSAPR the set-aside is for new 

units. 
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allowances. The EPA believes that the proposed approach of 

allocating allowances for a specified, but limited, period after 

a unit ceases operating is a reasonable middle ground approach. 

The proposed approach also allows the renewable energy setasides 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 

proposes that, if an affected EGU does not operate for two full 

calendar years, then starting with the next compliance period 

for which allowances have not yet been recorded, the allowances 

that would otherwise have been allocated to the unit would be 

allocated to the renewable energy 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 renewable energy 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 
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compliance period after the next compliance period the 

allowances would be allocated to the renewable energy 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 

the state in a pro-rata fashion (on the same distribution basis 

as the initial allocations were made), instead of allocating 

such allowances to the state’s renewable energy set-aside. The 

agency requests comment on a further alternative approach, which 

would be to continue allocations to the retired units. The EPA 

also requests comment on treatment of allocations to units that 

are in long-term cold storage. 

Units that are modified or reconstructed. Similar to the 

approach for an affected EGU that retires, the EPA proposes 

that, if a unit is modified or reconstructed such that it is no 

longer an affected EGU, then starting with the next compliance 

period for which allowances have not yet been recorded, the 

allowances that would otherwise have been allocated to the unit 
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would be allocated to the renewable energy set-aside. The EPA 

requests comment on this proposed approach, including on the 

number of years for which a unit would continue to receive 

allocations. The agency also requests comment on an alternative 

of distributing such allowances to the set-aside for outputbased allocations, or to the remaining affected EGUs in the 

state in a pro-rata fashion (on the same distribution basis as 

the initial allocations were made), instead of allocating such 

allowances to the state’s renewable energy set-aside. The agency 

requests comment on a further alternative approach, which would 

be to continue allocations to the modified or reconstructed 

units. 

E. State-determined Allowance Distribution 

The EPA proposes to allow any state to replace the EPAdetermined federal-plan allowance-distribution provisions in the 

mass-based trading program with state-developed allowancedistribution provisions. In this way, a state could choose how 

to distribute initial allowance allocations among its affected 

EGUs (and other entities). 

The EPA believes that this option may offer significant 

appeal, because it will allow a state to tailor its allocation 

approach to the characteristics and preferences of the state. A 

state would be able to design its allocation approach to address 
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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 the CSAPR and the CAIR where the EPA adopted 

rules allowing states to submit state implementation plans 

(SIPs) with provisions replacing the allowance-distribution 

provisions in the CSAPR or CAIR FIPs, respectively, while 

remaining in the trading programs under those FIPs (76 FR 48208; 

August 8, 2011, 71 FR 25328; April 28, 2006). In both CSAPR and 

CAIR, some states have chosen to determine their own allocations 

under the FIPs. This form of SIP that can replace the allowancedistribution provisions in CSAPR or CAIR is termed an 

“abbreviated SIP revision.” In this proposed mass-based trading 

federal plan, the EPA proposes that a state may choose to submit 
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a “state allowance-distribution methodology” (analogous to an 

abbreviated SIP revision) to replace the federal-plan allowancedistribution provisions with allowance-distribution provisions 

of its choosing. 

The mechanism the agency envisions is in the nature of a 

partial state plan or (for any future changes in a state’s 

allocation methodology) a partial state plan revision. (We 

request comment below on the advantages and disadvantages of 

allowing a state to handle allocations via a delegation of 

federal plan authority.) In general, under the proposed 

approach, the procedural requirements states and the agency must 

follow, including public notice requirements, for the submission 

and approval of state plans, would be required here. 

The EPA intends to provide the states with substantial 

flexibility in choosing approaches to distribute their 

allowances in a state allowance-distribution methodology. The 

EPA proposes that a state may choose any approach, including 

auctions or other methods the EPA is not proposing here, 

provided the state’s approach addresses leakage and also 

implements the Clean Energy Incentive Program. The EPA is also 

requesting comment on any other appropriate constraints to 

impose on state allowance-distribution methodologies. 

The Clean Power Plan EGs require mass-based state plans to 
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include a demonstration that they have addressed the risk of 

leakage, and the EGs provide several options for doing so (see 

section VIII.L of the final EGs). One of the options provided in 

the EGs is to address leakage through an allowance distribution 

approach that provides incentive to counteract leakage. In the 

mass-based trading federal plan, the EPA’s proposed approach to 

allocate allowances would address leakage using two allowance 

set-asides, one for output based allocation and one for 

renewable energy 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 

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 
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specified characteristics of the state (section VIII.L 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 Clean Power Plan EGs established a Clean Energy

Incentive Program (section VIII of the final EGs). The EPA 

proposes that a state allowance-distribution methodology, which 

would replace the federal-plan allocation provisions, must also 

include a Clean Energy Incentive Program, as detailed in section 

V.D.4 of this preamble. 

Under the proposed approach of providing for states to 

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 
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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 

allowance-distribution methodology does not change any other 

provisions in the proposed mass-based trading program, then the 

agency would likely approve the state allowance-distribution 

methodology. In the state allowance distribution methodology, 

the state could distribute allowances to affected EGUs or other 

entities (such as renewable energy 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 
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the state allowance-distribution provisions would apply, the 

total amount of allowances distributed could not exceed the 

applicable mass goal for that state for that year. A state’s 

methodology under this proposed approach could provide that the 

total amount of allowances distributed is less than the 

applicable mass goal.106 The EPA proposes that a state’s 

allowance-distribution provisions would replace the EPA’s 

allocation provisions completely – a state would not have the 

option of implementing only a portion of its allocations (e.g.,

only set-asides) and having the EPA implement the remainder of 

its allocations. Additionally, the EPA proposes that a state 

allowance-distribution methodology must provide for allowances 

to be issued in short tons. 

The allocation (or auction) of allowances would be final 

and could not be subject to modification. Additionally, the 

state’s provisions could not change any other provisions of the 

proposed mass-based trading program with regard to the 

allowances (e.g., the deadlines for allocation recordation, or 

 

106 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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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, 

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 
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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 unitlevel allowance 

table 

Deadline for the 

EPA to record 

allowances 

2022, 2023, 2024 March 1, 2020 March 1, 2021 June 1, 2021 

2025, 2026, 2027 March 1, 2023 March 1, 2024 June 1, 2024 

2028, 2029 March 1, 2026 March 1, 2027 June 1, 2027

2030, 2031* March 1, 2028* March 1, 2029* June 1, 2029* 

*This pattern of deadlines would hold for successive 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. 

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 
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state allowance-distribution methodology 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 

reasons that the agency proposes that a state may not replace a 

mass-based trading federal plan with a state plan for a future 

compliance period for which allowances have already been 

recorded, as discussed below in section V.F of this preamble. 

The agency requests comment on the proposed approach to 

allow states to determine allocations via state allowancedistribution methodologies and replace the federal-plan 

allowance-distribution provisions. The EPA requests comment on 
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the proposed schedule for submitting state allowance 

distribution methodologies to the agency, for submitting the 

resulting unit-level allowance tables to the agency, and for the 

agency to record allowances. The EPA requests comment on its 

proposed approach of not replacing EPA-determined allocations 

for a compliance period for which allowances have already been 

recorded. The agency also requests comment on an alternative 

approach where a state could notify the EPA of its intent to 

submit a state allowance-distribution methodology in advance, in 

which case the agency would hold off on recording EPA-determined 

allocations to allow more time for state-determined allowances 

to be recorded, similar to the alternative timing approach 

discussed in section V.F of this preamble. 

The EPA is also requesting comment on an alternative 

approach to provide the opportunity for a state to determine its 

allowance-distribution provisions in the federal plan mass-based 

trading program. The alternative approach on which the agency 

requests comment is to provide for a partial delegation of the 

federal plan – limited to the allowance-distribution provisions 

– to a state that wishes to determine its allowance-distribution 

provisions. The EPA requests comment on the relative efficiency 

and ease of implementation of the two approaches (the state 

allowance-distribution methodology described above, or the 
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partial delegation). The agency requests comment on whether the 

partial delegation approach would provide sufficient flexibility 

for a state to choose any method to distribute its allowances 

including approaches that the EPA is not proposing here. See 

further discussion of delegations in section VI of this 

preamble. 

F. Treatment of States Entering or Exiting the Trading Program 

If the EPA implements a mass-based trading program federal 

plan for any state, the agency will work with a state that 

wishes to replace the federal plan with an approved state plan 

to provide a smooth transition. The EPA proposes that a massbased trading federal plan could only be replaced by a state 

plan for a future compliance period for which allowances have 

not yet been recorded. For example, if a 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, 

the first compliance period for which a state could replace the 

federal plan with its own plan would be for the period 

commencing in 2025. The EPA is proposing this stipulation for 

the timing of replacing a federal plan with a state plan due to 

the need to avoid disruption to sources already subject to the 

mass-based trading federal plan. Without this stipulation, a 
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state might withdraw from the mass-based trading program in the 

middle of a compliance period even though allowances that 

authorize emissions throughout that entire compliance period 

would already be in circulation. In that circumstance, the EPA 

would then need to address whether and how to remove those 

allowances from circulation to prevent inflation of the 

allowable emissions at affected EGUs in the remaining states 

subject to the federal plans beyond the levels specified in the 

Clean Power Plan EGs. The EPA believes it is more reasonable to 

avoid this potential disruption by requiring that the 

replacement of a federal plan with a state plan be scheduled to 

coincide with the conclusion of the last compliance period for 

which allowances under the federal plan have already been 

recorded for that state. The EPA requests comment on other 

approaches to provide a smooth transition from federal-plan 

implementation to implementation by state plans, and on its 

proposed approach of not replacing a federal plan for any 

compliance period for which allowances were already recorded. 

The agency requests comment on an alternative of providing 

for a state to give notice to the EPA of its intent to submit a 

state plan to replace the federal plan (or a state allowancedistribution methodology to replace federal-plan allocations), 

and for the agency to delay recording federal-plan allocations 
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for sources in that state until a later date than proposed. The 

EPA requests comment on whether this alternative would help 

smooth the transition from federal-plan implementation to stateplan implementation, and on the trade-off between recording 

allowances in a timely way and providing this increased timing 

flexibility. 

G. Allowance Tracking, Compliance Operations, and Penalties 

The EPA proposes that the mass-based trading program use an 

allowance tracking and compliance system (ATCS) operated 

essentially the same way as the existing systems that are 

currently in use for Cross State Air Pollution Rule (CSAPR) and 

the Acid Rain Program (ARP) under Title IV. Under the proposed 

mass-based trading program, the CO2 program would be a separate 

trading program maintained in the EPA’s existing data system. 

ATCS would be used to track the trading of CO2 allowances held by 

covered affected EGUs in facility level compliance accounts, as 

well as such allowances held by other entities or individuals. 

Specifically, ATCS would track the allocation of all CO2

allowances, holdings of CO2 allowances in compliance accounts 

(i.e., a facility level account for all affected EGUs at the 

facility) and general accounts (i.e., accounts for other 

entities such as companies and brokers), deduction of CO2

allowances for compliance purposes, and transfers of allowances 
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between accounts. The primary role of ATCS is to provide an 

efficient, automated means for affected EGUs to comply, and for 

the EPA to determine whether affected EGUs are complying, with 

the emissions limitations and any other requirements of the 

mass-based trading program. ATCS would also provide data to the 

allowance market and the public, including a record of ownership 

of allowances, dates of allowance allocations, allowance 

transfers, buyer and seller information, serial numbers of 

allowances transferred, emissions, and compliance information. 

This information would be publicly available on the EPA’s Web 

site and in annual progress reports. 

1. Designated Representatives and Alternate Designated

Representatives 

 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 

to make electronic submissions to the Administrator. These 

provisions would be patterned after the provisions concerning 
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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 

plans, monitoring system certifications, and allowance 
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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
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Administrator for recordation, the Administrator would not be 

able to ensure that any reported price information associated 

with the transfers would reflect current market prices. 

3. Compliance and General Accounts 

 This section describes two types of Allowance Tracking and 

Compliance system accounts: Compliance accounts, one of which 

the Administrator would establish for each facility with an 

affected EGU upon receipt of the certificate of representation 

for the facility; and general accounts, which could be 

established by any entity upon receipt by the Administrator of 

an application for a general account. A compliance account would 

be the account in which any allowances used by an affected EGU 

for compliance with the emissions limitations would have to be 

held. The designated representative and alternate for the 

affected EGU would also be the authorized account representative 

and alternate for the compliance account. Using facility-level, 

rather than 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 
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enough allowances to meet these requirements for the entire 

facility. Facility-level compliance would also be consistent 

with other EPA-administered mass-based trading programs. 

 General accounts could be used by any person or group for 

holding or trading allowances. However, allowances could not be 

used for compliance with emissions limitations so long as the 

allowances were held in, and not properly and timely transferred 

out of, a general account. To open a general account, a person 

or group would have to submit an application for a general 

account, which would be similar in many ways to a certificate of 

representation. The application would include, in a format 

prescribed by the Administrator: the name and identifying 

information of the individual who would be the authorized 

account representative and of any individual who would be the 

alternate authorized account representative; an identifying name 

for the account; the names of all persons with an ownership 

interest with respect to allowances held in the account; and 

certification language and signatures of the authorized account 

representative and alternate. The authorized account 

representative and alternate would be authorized upon receipt of 

the application by the Administrator. The provisions for 

changing the authorized account representative and alternate, 

for changing the application to take account of changes in the 
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persons having an ownership interest with respect to allowances, 

and for delegating authority to make electronic submissions 

would be analogous to those applicable to comparable matters for 

designated representatives and alternates. 

4. Recordation of Allowance Allocations and Transfers 

 By June 1, 2021, the Administrator would record allowance 

allocations for 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 
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submitted to the Administrator and, when the Administrator 

attempted to record the transfer, the transferor account 

included the allowances identified in the form, the

Administrator would record the transfer by moving the allowances 

from the transferor account to the transferee account within 5 

business days of the receipt of the transfer form. 

5. Compliance with Emissions Limitations 

 Once the compliance period has ended (e.g., at midnight on 

December 31, 2024 for the first compliance period), facilities 

with affected EGUs would have a window of opportunity following 

the compliance period to evaluate their reported emissions and 

obtain any allowances that they might need to cover their 

emissions during the compliance period. For example, the 

allowance transfer deadline for the first compliance period 

would be midnight on May 1, 2025 (the EPA is also requesting 

comment on earlier or later allowance transfer deadlines). Each 

allowance issued in the proposed mass-based trading program 

would authorize emission of one ton of CO2 and so would be usable 

for compliance, for the compliance period that includes the year 

for which the allowance was allocated or a later compliance 

period. Consequently, each affected EGU would need, as of the 

allowance transfer deadline, to have in its facility compliance 

account, or to have a properly submitted transfer that would 
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move into its compliance account, enough allowances usable for 

compliance to authorize its total emissions for the compliance 

period. The authorized account representative could identify 

specific allowances to be deducted, but, in the absence of such 

identification or in the case of a partial identification, the 

Administrator would deduct on a first-in, first-out basis. 

Deducting allowances may have tax and accounting implications, 

so having a default deduction method provides the 

representatives with certainty regarding which allowances will 

be deducted for compliance. Allowances that are deducted for 

compliance will remain in the system in an EPA account, which 

ensures they will not be used again. If a facility were to 

fail to hold sufficient allowances for compliance by all 

affected EGUs at the facility, then the owners and operators of 

the facility and each affected EGU at the facility would have to 

provide, for deduction by the Administrator, two allowances 

allocated for the compliance period in the next year for every 

allowance that the owners and operators failed to hold as 

required to cover emissions. This submittal of two times the 

allowances required for the prior period is an ongoing 

obligation until compliance is achieved, and there is an ongoing 

obligation to comply in the current period. In addition, these 

owners and operators would be subject to civil penalties for 
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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 

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 
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submission, and deduct or transfer allowances based on such 

adjusted information. These provisions are a standard part of 

other trading programs administered by the EPA including the 

Acid Rain Program and Cross State Air Pollution Rule (see 40 CFR 

72.96, 73.37, 97.427, and 97.428). 

H. Emissions Monitoring and Reporting Requirements 

The EPA proposes that units subject to the mass-based 

federal plan trading program would monitor and report CO2 mass 

emissions in accordance with 40 CFR part 75. 

The EPA is proposing to require affected EGUs in all states 

covered by the mass-based federal plan trading program to 

monitor and report CO2 emissions and output data by January 1, 

2022. Quarterly reporting would be required, with each quarterly 

report due to the Administrator 30 days after the last day in 

the quarter. The reporting would be in accordance with 40 CFR 

part 75.60. The use of part 75 certified monitoring

methodologies would be required. Many EGUs that might be covered 

by the proposed federal plans will generally have no changes to 

their monitoring and reporting requirements and will continue to 

monitor and submit reports under part 75 as they have under 

existing programs. The EPA anticipates fewer than 50 affected 

EGUs that would not otherwise be subject to the Acid Rain 

Program will have to purchase and install additional CEMS and 
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data handling systems or upgrade existing equipment in order to 

meet the monitoring and reporting requirements of this program 

(the EPA anticipates approximately 10 coal fired units and 

approximately 40 gas and oil fired units will qualify for an 

excepted monitoring methodology). Several of the units not 

otherwise subject to the Acid Rain Program are subject to the 

MATS program and, therefore, will have already installed stack 

flow rate and/or CO2 monitors necessary to comply with this rule 

in order to comply with the MATS. The CEMS used to comply and 

report data for MATS will be used for this rule to generate and 

report CO2 emissions data without having to install duplicative 

monitors. The same CO2 and stack gas flow rate monitored data 

used in conjunction with Hg 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 
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for different purposes for multiple regulatory programs. 

The majority of the units covered by this rule are already 

affected by the Acid Rain and/or Regional Greenhouse Gas 

Initiative programs and will have minimal additional monitoring 

and reporting requirements. 

The EPA also requests comment on requiring monitoring and 

reporting of CO2 mass and net generation for the year before the 

initial compliance period begins, i.e., to commence January 1, 

2021. Only the monitoring and reporting would be required in 

2021 — compliance with the requirement to hold allowances would 

commence on the compliance period schedule that is detailed in 

section V.C of this preamble. 

VI. Implementation of the Federal Plan and Delegation 

Under section 111(d) of the CAA, the EPA adopts EGs that 

are then implemented when the EPA approves a state or tribal107

plan or promulgates a federal plan that implements and enforces 

the EG for affected EGUS in states or areas of Indian country108

 

107 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.

108 As discussed in detail in (citation), in adopting a federal 

plan implementing the EG in areas of Indian country containing 
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without an approved state or tribal plan. Congress has 

determined that the primary responsibility for air pollution 

prevention and control rests with state and local agencies, 

while also recognizing that “Federal ... leadership is essential 

for the development of cooperative Federal, State, regional, and 

local programs to prevent and control air pollution.” (See 

section 101(a)(3) and (4) of the CAA.) Congress has also 

provided for Indian Tribes meeting specified eligibility 

criteria to implement the CAA within the exterior boundaries of 

their reservations or other areas within the tribe’s 

jurisdiction. (See section 301(d)(1) and (2) of the CAA.) Even 

in the event that it becomes necessary for the EPA to directly 

regulate affected EGUS under CAA section 111(d), states and 

eligible tribes may still seek a delegation 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 

 

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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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.109 110 

A. Delegation of the Federal Plan and Retained Authorities 

If a state or tribe111 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 

 

109 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. 

110 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). 

111 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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criteria for delegation. See generally “Good Practices Manual 

for Delegation of NSPS and NESHAP” (EPA, February 1983). The 

letter requesting delegation of authority to implement the 

federal plan should: (1) Demonstrate that the state or tribe has 

adequate resources, as well as the legal and enforcement 

authority to administer and enforce the program, (2) include an 

inventory of affected EGUs, which includes those that have 

ceased operation but have not been dismantled, include an 

inventory of the affected units’ air emissions and a provision 

for state or tribal progress reports to the EPA, (3) certify 

that a public hearing has been held on the state or tribal 

delegation request, and (4) include a memorandum of agreement 

between the state or tribe and the EPA that sets forth the terms 

and conditions of the delegation, the effective date of the 

agreement and the mechanism to transfer authority. Upon 

signature of the agreement, the appropriate EPA Regional Office 

would publish an approval notice in the Federal Register, 

thereby incorporating the delegation of authority into the 

appropriate subpart of 40 CFR part 62. See also EPA’s 

Delegations Manual, Delegation 7-139, “Implementation and 

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.) 
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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 will retain and 

will not transfer authority to a state or tribe to approve the 

following items promulgated in the 2015 CAA section 111(d) Clean 

Power Plan: 

(1) [&&& DO WE HAVE A LIST OF ITEMS FOR WHICH EPA 

PREFERS TO MAINTAIN AUTHORITY?]

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 

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 
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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. 

Upon the effective date of an approved state or tribal 

plan, the federal plan would no longer apply to EGUs covered by 
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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 

handle the initial allocation of allowances in a mass-based 
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trading program, as discussed in section &&& 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 EG 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 
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appropriate and where authorized by state or tribal law. If a 

state or tribe requests delegation, the EPA will generally 

delegate the entire federal plan to the state or tribal agency, 

thereby providing authority to the state or tribe for things 

such as administration and oversight of compliance reporting and 

recordkeeping requirements, inspections of its affected EGUs, 

and enforcement. The EPA will continue to hold inspection, 

information gathering, enforcement, and other authorities along 

with the state or tribe even when a state or tribe has received 

delegation of the federal plan. The delegation will not include 

any authorities retained by the EPA. 

C. Implementing Authority 

The EPA Regional Administrators have been delegated the 

authority for implementing the federal plan. All reports 

required by the federal plan should be submitted to the 

appropriate Regional Administrator. Section II.C. 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 
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and Radiation within the Headquarters of the EPA is proposed to 

be the primary office within the agency with delegated CAA 

section 111(d)(2) authority. See Delegation 7-139, section 3(c). 

D. Necessary or Appropriate Finding for Affected EGUs in Indian 

Country 

Indian Tribes may, but are not required to, submit tribal 

plans to implement the Emission Guidelines (EG). 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 EG 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 
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to do so. In the final Emission Guidelines, 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 Uintah and Ouray Reservation, and lands of the Fort 

Mojave Tribe’s reservation. [&&&citation to final EGs]. The EPA 

proposed carbon pollution emission guidelines 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. &&&citation. 

In this action, we are proposing to find that it is necessary 

or appropriate, in each of the three areas of Indian country that 
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have affected EGUs, to establish a federal plan that applies to 

the four power plants located on the Navajo Nation, the Fort Mojave 

Indian Reservation, and the Uintah and Ouray Reservation of the 

Ute Tribe. The affected EGUs located on the Navajo Nation are in 

an area of Indian country located within the continental United 

States, are interconnected with the western electricity grid, and 

are owned and operated by entities that generate and provide 

electricity to customers in several states. The affected EGU 

located on the Uintah and Ouray Reservation of the Ute Tribe is in 

an area of Indian country located within the continental United 

States, is interconnected with the western electricity grid, and 

is owned and operated by an entity that generates and provides 

electricity to customers in several states. The affected EGU 

located on the Fort Mojave Indian Reservation is in an area of 

Indian country located within the continental United States, 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. 
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Because the agency has finalized emission performance targets 

for these power plants in the EGs, there is, in our view, little 

benefit to be had by not proposing to include them in a federal 

plan now and a potentially significant downside to not doing so; 

the reductions the EPA has determined are achievable in the EGs 

would become more difficult and costly for these power plants to 

achieve if they are delayed in entering into the trading program 

the agency intends to establish. In order to meet the performance 

targets, we are anticipating that the affected EGUs may need to 

secure allowances or ERCs (depending on the approach ultimately 

finalized) during the compliance periods. They may also be able to 

generate and sell compliance instruments by participating in the 

trading program. Thus, proposing a finding that it is necessary or 

appropriate to establish one or more federal plans providing the 

ability to participate in a rate- or mass-based trading program is 

in the interest of these four power plants located in areas of 

Indian country. We believe that this together with the facts that, 

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 
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that it is necessary or appropriate to establish one or more 

applicable federal plans at this time. 

We recognize that the governments of these tribes may still 

choose to seek TAS to develop a tribal plan, and this proposed 

determination does not preclude the tribes from taking such 

actions. We also note that this proposed determination does not 

preclude these tribes from seeking TAS and receiving delegation to 

administer aspects of any applicable federal plan that is 

ultimately promulgated. In the event a federal plan is needed, 

proposing a necessary or appropriate finding at this time will 

allow the EPA to expeditiously promulgate a final federal plan for 

one or all of these power plants in the future to allow trading to 

occur. We will continue to consult with the governments of the 

Navajo Nation, Fort Mojave Indian Tribe, and the Ute Tribe of the 

Uintah and Ouray Reservation during the comment period for this 

proposal, and prior to taking any action to finalize a necessary 

or appropriate finding and/or a federal plan. Comments on the 

appropriateness of the proposed finding, should be submitted 

within the comment period specified in 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 
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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 

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 
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enhance the administration of the 111d program. 

Section 111(d)(1) provides that the EPA “shall establish a 

procedure similar to that provided by CAA section [110] of this 

title under which each state shall submit to the Administrator a 

[111(d)] plan . . ..” 42 U.S.C. 7411(d)(1). Thus, the CAA 

directs the EPA to look to the structure of the SIP program when 

designing the procedures the states and agency will use to 

develop CAA section 111(d) plans. Notably, the CAA does not 

require the CAA section 111(d) procedures to be identical to 

those the EPA uses under CAA section 110 for SIPs.112 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 

 

112 See Webster’s II New Riverside University Dictionary (Riverside 

1988) (defining “similar” to mean “resembling though not 

completely identical”). 
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were promulgated in 1975 based on the structure of CAA section 

110 as Congress designed it in the 1970 CAA Amendments. See 40 

FR 53340-49 (Nov. 17, 1975). Over the years since 1970, the EPA 

and the states learned a great deal about the procedural 

limitations of the original SIP review process. The 1970 CAA 

only allowed the EPA to approve or disapprove SIP submittals. 

The agency struggled to deal responsively to situations where 

the EPA wanted to work with states to get state programs 

approved to the extent possible, while maintaining consistency 

with CAA requirements. Congress responded in 1990 and enhanced 

the procedural mechanisms the EPA has to act on SIPs. The EPA is 

proposing correspondingly to update the CAA section 111(d) 

regulations in a similar fashion. Currently, the EPA’s framework 

regulations for submittal and adoption of CAA section 111(d) 

state plans do not explicitly provide for the EPA to use some of 

the same procedures for approving or disapproving state plans 

Congress introduced into the SIP program in the 1990 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. 
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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.113 This is a particularly useful function when much of a 

state plan is approvable and the EPA and the state cannot reach 

resolution on only a small, severable portion of the state plan. 

In this case, the EPA prefers not to be in a position where it 

must disapprove the full plan, but rather to allow the state to 

move forward with those portions of the plan that are 

approvable. 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 

 

113 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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severable from each other, and one element is approvable while 

another is not, this provision will authorize the EPA to approve 

one part of a plan and disapprove the other. It will also 

authorize the EPA to accept and review a state plan that is only 

partial in nature, if identified by the state as such, so long 

as the other applicable submission requirements are met (such as 

demonstration of legal authority and completion of the public 

process). When the state submits what it intends to be a full 

state plan (rather than just a partial plan), the EPA proposes 

that the approvable portion of a plan must be functionally 

severable from the rest of the plan, and this will be the case 

when the following conditions are met. First, the approvable 

portion of the plan must not depend on the rest of the plan. In 

other words, the disapproval of the remaining portion of the 

plan must not affect the portion that is approved. Second, 

approval of the approvable portion must not alter the function 

of the submittal in a way that is contrary to the state’s 

intent. 

The partial disapproval would be a disapproval for the 

purposes of CAA section 111(d)(2)(A) and would trigger the EPA’s 

authority to issue a federal plan for the state, at least for 

that part of the plan that was disapproved. Incorporating this 

mechanism under the framework regulations for CAA section 111(d) 
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will enable the EPA to approve a state to implement as much of 

its program as is consistent with a CAA section 111(d) guideline 

and may reduce the scope of any federal plan that would be 

necessary. 

B. Conditional Approvals 

The second mechanism is the authority under CAA section 

110(k)(4) to conditionally approve a plan. Where a state has 

submitted a plan that substantially meets the requirements of a 

CAA section 111(d) emission guideline, but requires some 

specific amendments to make it fully approvable, this provision 

authorizes the EPA to conditionally approve the plan. The 

Governor or her designee must submit to the EPA a commitment 

that specifies the amendments to be adopted and submitted to the 

EPA by no later than 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. 

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 
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CAA section 111(d). 

C. Calls for Plan Revisions 

CAA section 110(k)(5) authorizes the EPA to find that a 

state implementation plan 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 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. 
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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.114

The effect of such a finding is that either the state 

submits the program corrections by the date the EPA sets in the 

notice, or pursuant to CAA section 111(d)(2)(A), the EPA has 

authority to issue a federal plan for a state that misses its 

deadline to correct its plan. In effect, the finding of plan 

inadequacy establishes a plan submittal deadline subject to the 

provisions of CAA section 111(d)(2)(A). A finding of failure to 

meet that new deadline triggers the EPA’s authority to issue a 

federal plan for the state. The EPA may promulgate a federal 

 

114 Consistent with the agency’s practice under CAA section 

110(k)(5), the EPA anticipates that a call for plan revisions under 

CAA section 111(d) will be done via notice and comment rulemaking. 
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plan at any time following the state’s failure to timely submit 

an adequate plan that addresses the EPA’s finding. 

While these authorities are important, the intention of 

having a mechanism to call for plan revisions is to have a way 

to initiate an orderly process to improve plans when they are 

not meeting program objectives. It is the EPA’s hope that a call 

for plan revision leads to a constructive dialogue with a state 

or states, and ultimately, an improved and more effective CAA 

section 111(d) plan. 

The EPA is also proposing that the agency can call for a 

plan revision in circumstances where a state is not implementing 

its approved state plan and, therefore, the state plan is 

substantially inadequate to provide for the implementation of 

CAA section 111(d) standards of performance. As discussed above, 

the CAA directs the EPA to develop a procedure for state plans 

under CAA section 111(d) similar to CAA section 110 SIP 

procedures. Calling a plan that is substantially inadequate to 

provide for implementation of standards of performance (i.e.,

there is a failure to implement a state plan) is one area where 

the EPA proposes it is appropriate to adapt the procedural 

mechanisms available in the SIP program to provide a similar 

process that assures effective state plan implementation under 

CAA section 111(d). Under CAA section 110(k)(5), the EPA may 
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call for a revision of a state plan “[w]henever the

Administrator finds that the . . . plan . . . is substantially 

inadequate to . . . comply with any requirement of [the Act].” 

If the state does not submit a plan revision in response to the 

call to cure the failure to provide for implementation, the EPA 

would have the authority to promulgate the federal plan being 

proposed. 

One critical requirement of CAA section 111(d)(1)(B) is 

that a state must submit a plan that “provides for the 

implementation and enforcement of such standards of performance” 

(emphasis added). If, after the EPA has approved a plan, a state 

fails to implement that plan, the plan has become substantially 

inadequate to comply with this requirement of the CAA. Under 

this proposal, the EPA’s remedy would be to find the plan is 

substantially inadequate, which triggers the state’s obligation 

to cure, and failing that, the EPA’s authority to promulgate the 

federal plan. 

In the alternative, the EPA proposes that this authority to 

call a plan for failure to implement is anchored in the 

authority provided under CAA section 110(k)(5) to call a SIP 

when the agency finds that it is “substantially inadequate to 

attain or maintain the relevant national ambient air quality 

standard.” In the context of CAA section 111, this authority 
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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 

to provide notice and a public hearing on each new SIP 
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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 
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submittal shall be a copy of the official state 

regulation/document signed, stamped and dated by the appropriate 

state official indicating that it is fully enforceable by the 

state. The effective date of the regulation/document shall, 

whenever possible, be indicated in the document itself. The 

state’s electronic copy must be an exact duplicate of the hard 

copy. For revisions to the approved plan, the submittal shall 

indicate the changes made (for example, by 

redline/strikethrough) to the approved plan; (5) evidence that 

the state followed all of the procedural requirements of the 

state's laws and constitution in conducting and completing the 

adoption/issuance of the plan; (6) evidence that public notice 

was given of the proposed change with procedures consistent with 

the requirements of 40 CFR 60.23, including the date of 

publication of such notice; (7) certification that public 

hearing(s) were held in accordance with the information provided 

in the public notice and the state's laws and constitution, if 

applicable and consistent with the public hearing requirements 

in 40 CFR 60.23; and (8) compilation of public comments and the 

state's response thereto. 

These criteria, as proposed, are intended to be generic to all 

CAA section 111(d) plans going forward, with the proviso that 

specific emission guidelines may provide otherwise. The 
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technical support completeness criteria that the EPA proposes 

will also be generic to all CAA section 111(d) rules, with the 

same proviso. The EPA proposes that the technical support 

required for all plans must include each of the following: (1) 

Description of the plan approach and geographic scope;(2) 

identification of each designated facility, identification of 

emission standards for the designated facilties, and monitoring, 

recordkeeping, and reporting requirements that will determine 

compliance by each designated facility; (3)identification of 

compliance schedules and/or increments of progress; (4) 

demonstration that the state plan submittal is projected to 

achieve emissions performance under the applicable EGs; (5) 

documentation of state recordkeeping and reporting requirements 

to determine the performance of the plan as a whole; and (6) 

demonstration that each emission standard is quantifiable, nonduplicative, permanent, verifiable, and enforceable. 

The EPA proposes a process similar, though not identical, 

to that set forth in 40 CFR 51.103 and Appendix V to 40 CFR part 

51 to make completeness determinations. Similar to CAA section 

110(k)(1)(C), under this proposal, where the EPA determines that 

a state submission required under CAA section 111(d) does not 

meet the minimum completeness criteria we are proposing to 

establish, the state will be considered to have not made the 
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submission. The EPA further proposes that, similar to CAA 

section 110(k)(1)(B), within 60 days of the EPA's receipt of a 

state submission, but no later than 6 months after the date, if 

any, by which a state is required to submit the plan or 

revision, the Administrator shall determine whether the minimum 

criteria have been met. Any plan or plan revision that a state 

submits to the EPA, and that has not been determined by the EPA 

by the date 6 months after receipt of the submission to have 

failed to meet the minimum criteria, shall on that date be 

deemed by operation of law to meet such minimum criteria. 

As with the completeness determination process for SIP 

submissions, the EPA’s determination that a submittal is 

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 
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submittal is complete, it does not prevent the agency from later 

finding that the state plan does not meet the requirements of 

the EGs, including finding that the submittal failed to address 

a required element and must be disapproved. 

Similarly, when a submittal is determined to be complete by 

operation of law after 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. 
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 As described in the final rulemaking notice for the CAA 

section 111(d) EGs, a state will submit all CAA section 111(d) 

plans electronically. If the EPA determines that any submission 

fails to meet the completeness criteria, the agency may return 

the plan to the state and request corrections, identifying the 

components that are absent or insufficient to allow the EPA to 

perform a review of the plan. The state will not have met its 

obligation to submit a final plan until it resubmits a revised 

state plan or supporting materials addressing the corrections 

the EPA identified in its incompleteness determination. 

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. 
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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 

The EPA proposes to update the deadlines for acting on 

state submittals and promulgating a federal plan under 40 CFR 

60.27(b), (c), and (d) to more closely track the current 

versions of CAA section 110(c) and 110(k) adopted in 1990. The 

framework regulations for CAA section 111(d) state plans 

currently are parallel to the prior version of CAA section 110. 

They require the EPA to act on a state plan or plan revision 

submittal within 4 months after the date required for submission 

of a plan or plan revision. 40 CFR 60.27(b). The regulations 

then require the EPA to issue a proposed federal plan in certain 

circumstances after consideration of any state hearing record, 

40 CFR 60.27(c), and require the EPA to promulgate the proposed 

federal plan within 6 months after the date required for plan 

submissions, id. 60.27(d). 

The final carbon dioxide EGs for Electric Utility 

Generating Units (EGUs) have already adjusted the deadline in 

60.27(b) to require the EPA to act on a state plan under those 

EGs within 12 months (rather than 4 months) after the date 
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required for submission of a plan. See 40 CFR 60.5715. However, 

the Clean Power Plan EGs did not modify the 6 month deadline for 

a federal plan in 60.27(d). 

The EPA is proposing to amend 40 CFR 60.27(b) to allow the 

EPA 12 months to approve or disapprove submittals of all plans 

or plan revisions under CAA section 111(d), not just those 

related to the Clean Power Plan under 60.5715. This change would 

provide the EPA with sufficient time for the steps 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 
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60.27(d) to 1 year115; and, similar to the change in timing for 

60.27(b) above, setting the deadline for promulgation of a 

federal plan to run from the date of the EPA's action on a state 

submittal, rather than from the original deadline for a state 

submittal. 

The EPA believes it is appropriate to modify these timing 

requirements for several reasons. First, the EPA notes that 

under CAA section 111(d)(2), Congress gave the EPA the "same" 

authority to prescribe a federal plan under CAA section 111(d) 

as it would have under CAA section 110(c) in the case of a state 

failure to submit a SIP. The term "same" stands in contrast to 

the term "similar" in CAA section 111(d)(1) (discussed above). 

As with the use of the term “similar,” the EPA believes it is 

authorized by this language to follow the timing provisions of 

CAA section 110(c) as currently enacted. Second, as a general 

 

115 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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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 

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 
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the framework regulations. The EPA notes that the addition of 

these mechanisms to the framework regulations will make them 

available for all CAA section 111(d) regulations, not just those 

under the Clean Power Plan at Subpart UUUU. 

F. Proposed Interpretation regarding Existing Sources that Modify 

or Reconstruct 

In the proposed rulemaking for the CPP, the EPA proposed 

the interpretation that if an existing source is subject to a 

CAA section 111(d) state plan, and then undertakes a 

modification or reconstruction, the source remains subject to 

the state plan, while also becoming subject to the modification 

or reconstruction requirements. 79 FR 34830, 34903–4. The EPA 

did not finalize a position on this issue in the final EGs rule, 

but indicated that it would re-propose and take comment on this 

issue through this federal plan rulemaking. The EPA also stated 

deferral of action on this issue does not impact states’ and 

affected EGUs’ pending obligations under this final rule 

relating to plan submission deadlines, as this issue concerns 

potential obligations or impacts after an existing source has 

already become subject to the requirements of a state plan. The 

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 
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obligations on existing sources are effectuated. 

We noted in the Clean Power Plan proposal that CAA section 

111(d) is arguably silent as to this issue. Thus, we took this 

to grant the agency the authority to provide a reasonable 

interpretation to fill in the gaps where the statute is silent. 

In the proposal for the CPP, we proposed to disallow existing 

sources to leave the CAA section 111(d) program through 

modification or reconstruction. We did this for two reasons. 

First, if a source did so, that could prove disruptive to the 

state plan. Second, allowing sources to do so could provide them 

an incentive to do so that would be contrary to the purposes of 

CAA section 111(d). We then asked for comment on “whether this 

interpretation is supported by the statutory text and whether 

this interpretation is sensible policy and will further the 

goals of the statute.” 

We received many comments disagreeing with this approach. 

After reviewing these comments, the agency believes an 

alternative interpretation is more appropriate in the particular 

context here. In order to give the public an opportunity to 

comment on this, we are proposing this interpretation here. That 

is, when CAA section 111(d) emission guidelines are initially 

promulgated for existing stationary sources in response to 

corresponding CAA section 111(b) standards of performance for 
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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 NSPS) from simultaneously being subject 

to state plans under those particular CAA section 111(d) 

emission guidelines. This interpretation gives meaning to the 

definition of “existing source” in CAA section 111(a)(6) and is 

consistent with the definition of “new source” in section 

111(a)(2). Further, it is consistent with the historical 

treatment of modified and reconstructed sources in the CAA 

section 111 program. 

The EPA notes the concerns it noted in the proposal

supporting why the originally proposed interpretation was 

reasonable are being addressed in other ways in the final EGs, 

and in the proposed federal plan. In other words, there will be 

other ways to minimize disruption to state plans if such a 

modification or reconstruction were to take place. We invite 

comment on the agency’s proposed interpretation that when an 

existing source modifies or reconstructs in such a way that it 

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 
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G. Separate Finalization of these Changes 

The agency intends to finalize these procedural changes and 

interpretation sooner than it finalizes the rest of this 

proposed action. The EPA believes these changes generally 

enhance and improve the framework regulations in a way that will 

be of benefit to the states, the EPA, and other stakeholders, 

and will improve the overall efficacy of the program. We believe 

it is important to finalize these changes to the framework 

regulations relatively quickly in order to provide states and 

other stakeholders predictability in how the EPA intends to 

process state plans and submissions under CAA section 111(d). If 

the EPA does finalize these changes sooner than the model 

trading rules or the federal plan, it will do so after the close 

of the comment period, and after consideration and response to 

any comments on these changes. 

VIII. Impacts of this Action 

A. Endangered Species Act 

Consistent with the requirements of section 7(a)(2) of the 

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 
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or designated critical habitat. Section 7(a)(2) of the ESA 

requires federal agencies, in consultation with the U.S. Fish 

and Wildlife Service (FWS) and/or the National Marine Fisheries 

Service, to ensure that actions they authorize, fund, or carry 

out are not likely to jeopardize the continued existence of 

federally listed endangered or threatened species or result in 

the destruction or adverse modification of designated critical 

habitat of such species. 16 U.S.C. 1536(a)(2). Under relevant 

implementing regulations, ESA section 7(a)(2) applies only to 

actions where there is discretionary federal involvement or 

control. 50 CFR 402.03. Further, under the regulations 

consultation is required only for actions that “may affect” 

listed species or designated critical habitat. 50 CFR 402.14. 

Consultation is not required where the action has no effect on 

such species or habitat. Under this standard, it is the federal 

agency taking the action that evaluates the action and 

determines whether consultation is required. See 51 FR 19926, 

19949 (June 3, 1986). Effects of an action include both the 

direct and indirect effects that will be added to the 

environmental baseline. 50 CFR 402.02. Direct effects are the 

direct or immediate effects of an action on a listed species or 
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its habitat.116 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 

net positive environmental effect by virtue of reducing 

emissions of certain air pollutants does not address whether the 

 

116 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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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 

GHG emissions and effects on the species in its habitat.117 The 

 

117 See, e.g., 73 FR 28212, 28300 (May 15, 2008); Memorandum from 

David Longly Bernhardt, Solicitor, U.S. Department of the Interior 
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DOI Solicitor concluded that where the effect at issue is 

climate change, proposed actions involving GHG emissions cannot 

pass the “may affect” test of the ESA section 7 regulations and, 

thus, are not subject to ESA consultation. 

The EPA has also previously considered issues relating to GHG 

emissions in connection with the requirements of ESA section 

7(a)(2). In the final EGs, the agency noted that, although the GHG 

emission reductions projected for the Emissions Guidelines 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,118 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, timeattenuated changes in global metrics to particular effects on 

listed species in particular areas. Extrapolating from global 

 

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). 

118 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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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 Emissions 

Guidelines). However, CAA section 111(d) cannot directly control 

emissions of criteria pollutants. And furthermore, a federal 

plan under CAA section 111(d)(2) does no more than prescribe 

emissions standards of the same stringency as the corresponding 

EGs. 40 CFR 60.27(e)(1). Consequently, CAA section 111(d) 

provides no discretion to set a standard in a federal plan based 

on potential impacts to endangered species of reduced criteria 

pollutant emissions. ESA section 7(a)(2) consultation is not 

required with respect to the projected reductions of criteria 

pollutant emissions. See 50 CFR 402.03; see also WildEarth 

Guardians v. U.S. Envt’l Protection Agency, 759 F.3d 1196, 1207-

10 (10th Cir. 2014) (the EPA has no duty to consult under 

section 7 of the ESA regarding hazardous air pollutant 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 
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increased utilization of solar or wind power could have effects on 

listed species. The EPA received comments on the EGs asserting 

that because potential increased reliance on wind or solar power 

may be an element of Building Block 3, and because wind and solar 

facilities may in some cases have effects on listed species, the 

EPA must consult under the ESA on this aspect of the rule. 

The EPA has carefully considered the comments and the 

correspondence from Congress as well as the case law and other 

materials cited in those documents. The EPA does not believe that 

the effects of potential future changes in the energy sector – 

including increased reliance on wind or solar power as a result of 

future potential actions by states or other implementing entities 

– or any potential alterations in the operations of any particular 

facility would, at the time of promulgation of a federal plan, be 

sufficiently certain to occur so as to require ESA consultation on 

the rule. The EPA appreciates that the ESA regulations call for 

consultation where actions authorized, funded, or carried out by 

federal agencies may have indirect effects on listed species or 

designated critical habitat. However, as noted above, indirect 

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 
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proposed federal plan, any effects on listed species or designated 

habitat are too uncertain to require consultation under ESA section 

7. This is so for at least two reasons: (1) The EPA cannot know 

with any certainty at this stage which states will actually become 

subject to a finally promulgated federal plan. Which affected EGUs, 

in which states, will be covered by this Plan can only be known 

after states have failed to submit a plan, or have had their plans 

disapproved by the EPA; and (2), the federal plan as proposed will 

be implemented through some form of emissions trading. Emissions 

trading inherently provides maximum flexibility to individual 

affected EGUs to choose their method of compliance, including 

continuing to emit the relevant pollutant at historical rates so 

long as the affected EGU holds sufficient credits or allowances. 

At this point, the EPA has no meaningful information to express in 

any more than the broadest terms how any particular affected EGU 

may choose to comply with the federal plan, should it be 

promulgated for them based on their location in an area not covered 

by an approved state plan. The Services have explained that ESA 

section 7(a)(2) was not intended to preclude federal actions based 

on potential future speculative effects.119 These are precisely the 

 

119 See 51 FR at 19933 (describing effects that are “reasonably 

certain to occur” in the context of consideration of cumulative 
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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 

 

effects and distinguishing broader consideration that may be 

appropriate in applying a procedural statute such as the National 

Environmental Policy Act, as opposed to a substantive provision 

such as ESA section 7(a)(2) that may prohibit certain federal 

actions); Endangered Species Consultation Handbook, U.S. Fish & 

Wildlife Service and National Marine Fisheries Service at 4-

30(March 1998) (in the same context, describing indicators that an 

activity is reasonably certain to occur as including governmental 

approvals of the action or indications that such approval is 

imminent, project sponsors’ assurance that the action will 

proceed, obligation of venture capital, or initiation of 

contracts; and noting that the more governmental administrative 

discretion remains to be exercised, the less there is reasonable 

certainty the action will proceed). 
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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 Emission Guidelines. 

However, at the time of this proposal, the EPA has no 

information on whether any or how many states will require a 

federal plan or will adopt a model rule. Because of this lack of 

information, in the 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.120

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. 

 

120 It is important to note that the differences between the 

analytical results for the rate-based and mass-based federal 

plan approaches presented may not be indicative of likely 

differences between the approaches. If one approach performs 

differently than the other on a given metric during a given time 

period, this does not imply this will apply in all instances. 
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Under the mass-based approach, when compared to 2005, CO2

emissions are projected to be reduced by approximately 23 

percent in 2020, 29 percent in 2025, and 32 percent in 2030. The 

proposal is projected to result in substantial co-benefits 

through reductions of SO2, NOX and PM2.5 that will have direct 

public health benefits by lowering ambient levels of these 

pollutants and ozone. Table 12 and Table 13 of this preamble 

show expected CO2 and other air pollutant emissions in the base 

case and reductions under the proposal for 2020, 2025, and 2030 

for both rate-based and mass-based approaches. 

Table 12. Summary of CO2 and Other Air Pollutant Emission 

Reductions from the Base Case under Rate-Based Federal Plan 

Approach 

 

CO2

(millions 

short tons) 

SO2

(thousand 

short tons) 

NOX 

(thousand 

short tons) 

2020 

Base Case 2,155 1,311 1,333 

Rate-based Federal Plan 

Approach 

2,085 1,297 1,282 

Emissions Reductions 69 14 50 

2025 

Base Case 2,165 1,275 1,302 

Rate-based Federal Plan 

Approach 

1,933 1,097 1,138 

Emissions Reductions 232 178 165 

2030 

Base Case 2,227 1,314 1,293 

Rate-based Federal Plan 1,812 996 1,011 
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Approach

Emissions Reductions 415 318 282

Source: Integrated Planning Model, 2015. 

Note: Emissions may not sum due to rounding. 

Table 13. Summary of CO2 and Other Air Pollutant Emission 

Reductions from the Base Case under Mass-Based Federal Plan 

Approach 

 

CO2

(million 

short tons) 

SO2

(thousand 

short tons) 

NOX 

(thousand 

short tons) 

2020 

Base Case 2,155 1,311 1,333 

Mass-based Federal Plan 

Approach 

2,073 1,257 1,272 

Emissions Reductions 81 54 60 

2025 

Base Case 2,165 1,275 1,302 

Mass-based Federal Plan 

Approach 

1,901 1,090 1,100 

Emissions Reductions 265 185 203 

2030 

Base Case 2,227 1,314 1,293 

Mass-based Federal Plan 

Approach 

1,814 1,034 1,015 

Emissions Reductions 413 280 278 

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 hazardous air pollutants (HAPs) that 

may occur as a result of this rule. For instance, the fine 
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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.B of this preamble and presented in 

the RIA for this proposal. 

Table 14. Summary Table of Important Energy Market Impacts for 

Rate-Based and Mass-Based Federal Plan Approaches (Percent 

Change from Base Case) 

 Rate-Based Mass-Based 

 2020 2025 2030 2020 2025 2030 

Retail electricity 

prices 

3% 1% 1% 3% 2% 0% 

Average electricity 

bills 

3% -4% -7% 2% -3% -8% 

Price of coal at 

minemouth 

-1% -5% -4% -1% -5% -3% 

Coal production for 

power sector use 

-5% -14% -25% -7% -17% -24% 

Price of natural gas 

delivered to power 

sector 

5% -8% 2% 4% -3% -2% 

Natural gas use for 

electricity generation 

3% -1% -1% 5% 0% -4% 
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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. 

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 
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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 

some markets outside the utility power sector. Similarly, demand 

for new generation or DS-EE as a result of states implementing 

the guidelines can result in shifts in production and 

profitability for firms that supply those goods and services. 
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Executive Order 13563 directs federal agencies to consider 

the effect of regulations on job creation and employment. 

According to the Executive Order, “our regulatory system must 

protect public health, welfare, safety, and our environment 

while promoting economic growth, innovation, competitiveness, 

and job creation. It must be based on the best available 

science.” (Executive Order 13563, 2011) Although standard 

benefit-cost analyses have not typically included a separate 

analysis of regulation-induced employment impacts, we typically 

conduct employment analyses. While the economy continues to move 

toward full employment, employment impacts are of particular 

concern and questions may arise about their existence and 

magnitude. 

 The EPA’s employment analysis includes projected employment 

impacts associated with modeled federal plan approaches for the 

electric power industry, coal and natural gas production, and 

DS-EE activities. These projections are derived, in part, from a 

detailed model of the utility power sector used for this 

regulatory analysis, and U.S government data on employment and 

labor productivity. In the electricity, coal, and natural gas 

sectors, the EPA estimates that the proposed action could result 

in a net decrease of approximately 25,000 job-years in 2025 

under the rate-based federal plan approach and approximately 
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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 

elsewhere. This analysis also does not capture potential 

economy-wide impacts due to changes in prices (of fuel, 
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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 

$4.6 billion in 2020, $18 to $28 billion in 2025, and $34 to $54 
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billion in 2030 (3 percent discount rate, 2011$). 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

 

Discount Rate 

(Statistic) 

Monetized Climate Benefits 

YEAR 2020 2025 2030 

Rate-based Federal Plan Approach 

CO2 

Reductions 

(million 

short tons) 

 69 232 415 

 

5 percent (average 

SC-CO2) 

$0.80 $3.1 $6.4 

3 percent (average 

SC-CO2) 

$2.8 $10 $20 

2.5 percent 

(average SC-CO2)

$4.1 $15 $29 

3 percent (95th

percentile SC-CO2) 

$8.2 $31 $61 

Mass-based Federal Plan Approach 
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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 non-CO2 GHG emissions. These estimates are 

based on the global social cost of carbon (SC-CO2) estimates for 

the analysis years and are rounded to two significant figures. 

Table 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 

Monetized 

Health Cobenefits 

(3 percent 

discount) 

(7 percent 

discount) 

Rate-based Federal Plan Approach, 2020 

PM2.5 precursors b 

SO2 14 

$0.44 to 

$0.99 

$0.39 to 

$0.89 
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NOX 50 

$0.14 to 

$0.33

$0.13 to 

$0.30

Ozone precursor c 

NOX (ozone season only) 19 

$0.12 to 

$0.52

$0.12 to 

$0.52

Total Monetized Health Co-benefits 

$0.70 to 

$1.8

$0.64 to 

$1.7

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$3.5 to $4.6 $3.5 to $4.5

Rate-based Federal Plan Approach, 2025 

PM2.5 precursors b 

SO2 178 $6.4 to $14 $5.7 to $13 

NOX 165 

$0.56 to 

$1.3

$0.50 to 

$1.1

Ozone precursor c 

NOX (ozone season only) 70 

$0.49 to 

$2.1 

$0.49 to 

$2.1 

Total Monetized Health Co-benefits $7.4 to $18 $6.7 to $16

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$18 to $28 $17 to $26 

Rate-based Federal Plan Approach, 2030 

PM2.5 precursors b

SO2 318 $12 to $28 $11 to $25 

NOX 282 $1.0 to $2.3

$0.93 to 

$2.1 

Ozone precursor c

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 
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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 cobenefits do not include the benefits of reductions in directly 

emitted PM2.5. These additional benefits would increase overall 

benefits by a few percent based on the analyses conducted for 

the proposed Clean Power Plan EGs. PM co-benefits are shown as a 

range reflecting the use of two concentration-response 

functions, with the lower end of the range based on a function 

from Krewski et al. (2009) and the upper end based on a function 

from Lepeule et al. (2012). These models assume that all fine 

particles, regardless of their chemical composition, are equally 

potent in causing premature mortality because the scientific 

evidence is not yet sufficient to allow differentiation of 

effect estimates by particle type. 

c The monetized ozone co-benefits reflect the human health 

benefits associated with reducing exposure to ozone through 

reductions of NOX during the ozone season. Ozone co-benefits are 

shown as a range reflecting the use of several different 

concentration-response functions, with the lower end of the 

range based on a function from Bell, et al. (2004) and the upper 

end based on a function from Levy, et al. (2005). Ozone cobenefits occur in the analysis year, so they are the same for 
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all discount rates. 

d We estimate climate benefits associated with four different 

values of a one ton CO2 reduction (model average at 2.5 percent 

discount rate, 3 percent, and 5 percent; 95th percentile at 3 

percent). Referred to as the social cost of carbon, each value 

increases over time. For the purposes of this table, we show the 

benefits associated with the model average at 3 percent discount 

rate, however we emphasize the importance and value of 

considering the full range of social cost of carbon values. We 

provide combined climate and health estimates based on 

additional discount rates in the RIA. 

Table 17. Summary of the Monetized Health Co-Benefits in the 

U.S. for the Proposal, Mass-based Federal Plan Approach 

(Billions of 2011$)a 

Pollutant 

National 

Emission 

Reductions 

(thousands 

of short 

tons) 

Monetized 

Health Cobenefits 

Monetized 

Health Cobenefits 

(3 percent 

discount) 

(7 percent 

discount) 

Mass-based Federal Plan Approach, 2020 

PM2.5 precursors b 

SO2 54 $1.7 to $3.8 $1.5 to $3.4

NOX 60 

$0.17 to 

$0.39 

$0.16 to 

$0.36 

Ozone precursor c 

NOX (ozone season only) 23 

$0.14 to 

$0.61 

$0.14 to 

$0.61 

Total Monetized Health Co-benefits $2.0 to $4.8 $1.8 to $4.4

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$5.3 to $8.1 $5.1 to $7.7
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Mass-based Federal Plan Approach, 2025 

PM2.5 precursors b 

SO2 185 $6.0 to $13 $5.4 to $12 

NOX 203 

$0.58 to 

$1.3 

$0.52 to 

$1.2 

Ozone precursor c 

NOX (ozone season only) 88 

$0.56 to 

$2.4 

$0.56 to 

$2.4 

Total Monetized Health Co-benefits $7.1 to $17 $6.5 to $16 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$19 to $29 $18 to $27 

Mass-based Federal Plan Approach, 2030 

PM2.5 precursors b

SO2 280 $10 to $23 $9.0 to $20 

NOX 278 

$0.87 to 

$2.0 

$0.79 to 

$1.8 

Ozone precursor c

NOX (ozone season 

only) 

121 

$0.82 to 

$3.5 

$0.82 to 

$3.5 

Total Monetized Health Co-benefits $12 to $28 $11 to $26 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$32 to $48 $31 to $46 

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. 
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b The monetized PM2.5 co-benefits reflect the human health 

benefits associated with reducing exposure to PM2.5 through 

reductions of PM2.5 precursors, such as SO2 and NOX. The cobenefits do not include the benefits of reductions in directly 

emitted PM2.5. These additional benefits would increase overall 

benefits by a few percent based on the analyses conducted for 

the proposed Clean Power Plan EGs. PM co-benefits are shown as a 

range reflecting the use of two concentration-response 

functions, with the lower end of the range based on a function 

from Krewski et al. (2009) and the upper end based on a function 

from Lepeule et al. (2012). These models assume that all fine 

particles, regardless of their chemical composition, are equally 

potent in causing premature mortality because the scientific 

evidence is not yet sufficient to allow differentiation of 

effect estimates by particle type. 

c The monetized ozone co-benefits reflect the human health 

benefits associated with reducing exposure to ozone through 

reductions of NOX during the ozone season. Ozone co-benefits are 

shown as a range reflecting the use of several different 

concentration-response functions, with the lower end of the 

range based on a function from Bell, et al. (2004) and the upper 

end based on a function from Levy, et al. (2005). Ozone cobenefits occur in the analysis year, so they are the same for 

all discount rates. 

d We estimate climate benefits associated with four different 

values of a one ton CO2 reduction (model average at 2.5 percent 

discount rate, 3 percent, and 5 percent; 95th percentile at 3 

percent). Referred to as the social cost of carbon, each value 

increases over time. For the purposes of this table, we show the 

benefits associated with the model average at 3 percent discount 

rate, however we emphasize the importance and value of 

considering the full range of social cost of carbon values. We 

provide combined climate and health estimates based on 

additional discount rates in the RIA. 
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The EPA has used the social cost of carbon (SC-CO2) 

estimates presented in the Technical Support Document: Technical 

Update of the Social Cost of Carbon for Regulatory Impact 

Analysis Under Executive Order 12866 (May 2013, Revised July 

2015) (“current TSD”) to analyze CO2 climate impacts of this 

rulemaking.121 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 

 

121 Docket ID EPA-HQ-OAR-2013-0495, Technical Support Document: 

Technical Update of the Social Cost of Carbon for Regulatory 

Impact Analysis Under Executive Order 12866, Interagency Working 

Group on Social Cost of Carbon, with participation by Council of 

Economic Advisers, Council on Environmental Quality, Department 

of Agriculture, Department of Commerce, Department of Energy, 

Department of Transportation, Domestic Policy Council, 

Environmental Protection Agency, National Economic Council, 

Office of Management and Budget, Office of Science and 

Technology Policy, and Department of Treasury (May 2013, Revised 

July 2015). Available at: 

http://www.whitehouse.gov/sites/default/files/omb/inforeg/scctsd-final-july-2015.pdf. 
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system costs, such as reduced costs for heating and increased 

costs for air conditioning. It is typically used to assess the 

avoided damages as a result of regulatory actions (i.e., 

benefits of rulemakings that lead to an incremental reduction in 

cumulative global CO2 emissions). 

The SC-CO2 estimates used in this analysis were developed 

over many years, using the best science available, and with 

input from the public. Specifically, an interagency working 

group (IWG) that included the EPA and other executive branch 

agencies and offices used three integrated assessment models 

(IAMs) to develop the SC-CO2 estimates and recommended four 

global values for use in regulatory analyses. The SC-CO2

estimates were first released in February 2010 and updated in 

2013 using new versions of each IAM. The 2010 SC-CO2 Technical 

Support Document (2010 TSD)122 provides a complete discussion of 

 

122 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). 
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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).123 

OMB’s Office of Information and Regulatory Affairs received 

comments in response to a request for public comment on the 

approach used to develop the estimates. After careful evaluation 

of the full range of comments submitted to OMB, the IWG 

continues to recommend the use of the SC-CO2 estimates in 

regulatory impact analysis.124 With the release of the response 

 

Also available at: 

http://www.whitehouse.gov/sites/default/files/omb/inforeg/foragencies/Social-Cost-of-Carbon-for-RIA.pdf. 

123 The current version of the TSD is available at: 

https://www.whitehouse.gov/sites/default/files/omb/inforeg/sccresponse-to-comments-final-july-2015.pdf, Docket ID EPA-HQ-OAR2013-0495, Technical Support Document: Technical Update of the

Social Cost of Carbon for Regulatory Impact Analysis Under 

Executive Order 12866, Interagency Working Group on Social Cost 

of Carbon, with participation by Council of Economic Advisers, 

Council on Environmental Quality, Department of Agriculture, 

Department of Commerce, Department of Energy, Department of 

Transportation, Domestic Policy Council, Environmental 

Protection Agency, National Economic Council, Office of 

Management and Budget, Office of Science and Technology Policy, 

and Department of Treasury (May 2013, Revised July 2015). 

124 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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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 

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 
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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 regulatory impact 

analysis, including for this proceeding. 

The four SC-CO2 estimates are as follows: $12, $40, $60, and 

$120 per short ton of CO2 emissions in the year 2020 (2011$).125

The first three values are based on the average SC-CO2 from the 

three IAMs, at discount rates of 5, 3, and 2.5 percent, 

respectively. The SC-CO2 value at several discount rates are 

included because the literature shows that the SC-CO2 is quite 

sensitive to assumptions about the discount rate, and because no 

consensus exists on the appropriate rate to use in an 

intergenerational context (where costs and benefits are incurred 

 

125 The current version of the TSD is available at: 

https://www.whitehouse.gov/sites/default/files/omb/inforeg/scctsd-final-july-2015.pdf. The 2010 and 2013 TSDs present SC-CO2 in 

2007$ per metric ton. The estimates were adjusted to (1) Short 

tons for using conversion factor 0.90718474 and (2) 2011$ using 

GDP Implicit Price Deflator, http://www.gpo.gov/fdsys/pkg/ECONI2013-02/pdf/ECONI-2013-02-Pg3.pdf. 
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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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Page 420 of 478

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 BenMAP126 to calculate average regional benefit-per-ton 

estimates using the health impact assumptions used in the PM 

 

126 http://www.epa.gov/airquality/benmap/index.html
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NAAQS RIA127 and Ozone NAAQS RIAs.128,129 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.130 All benefit-per-ton estimates 

 

127 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. 

128 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>.

129 U.S. Environmental Protection Agency (U.S. EPA). 2010. Section 

3: Re-analysis of the Benefits of Attaining Alternative Ozone 

Standards to Incorporate Current Methods. Available at: 

http://www.epa.gov/ttnecas1/regdata/RIAs/s3-

supplemental_analysis-updated_benefits11-5.09.pdf. 

130 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 
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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 

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)131 and 

Lepeule et al. (2012)132. 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 

 

Standards, January. Available at: 

http://www.epa.gov/airquality/benmap/models/Source_Apportionment

_BPT_TSD_1_31_13.pdf. 

131 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. 

132 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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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, 

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)133 as a characterization of uncertainty 

 

133 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. 
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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)134 and the upper end based on a 

benefit-per-ton estimate using the function from Levy et al. 

(2005).135 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,136 which evaluated the substantial body of 

 

134 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. 

135 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. 

136 U.S. Environmental Protection Agency. 2009. Integrated 

Science Assessment for Particulate Matter (Final Report). 

Research Triangle Park, NC: National Center for Environmental 

Assessment, RTP Division. (EPA document number EPA-600-R-08-

139F, December). Available at: 

http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546. 
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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. 

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,137 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 

 

137 In addition, site-specific emission reductions will depend 

upon how states implement the guidelines. 
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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. 

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 
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Page 427 of 478

assessment found in the 2012 PM2.5 National Ambient Air Quality 

Standard (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-perton 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, 

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. 
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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 

environmental justice issue. Low-income communities and 

communities of color already overburdened with pollution are 

likely to be disproportionately affected by, and less resilient 

to, the impacts of climate change. This rulemaking will provide 

broad benefit to communities across the nation, as its purpose 

is to reduce greenhouse gases, the most significant driver of 

climate change. While addressing climate change will provide 

broad benefits, it is particularly beneficial to low-income 

populations and some communities of color (in particular, 

populations defined jointly by ethnic/racial characteristics and 

geographic location) where people are most vulnerable to the 

impacts of climate change (a more robust discussion of the 

impacts of climate change on vulnerable communities is provided 

in the Executive Order 12898 section XII.J of this preamble). 
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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 greenhouse 

gases also have the highest emissions of conventional 

pollutants, such as SO2, NOx, fine particles, and HAP. These 

pollutants are known to contribute to adverse health outcomes, 

including the development of heart or lung diseases, such as 

asthma and bronchitis, increased susceptibility to respiratory 

and cardiac symptoms, greater numbers of emergency room visits 

and hospital admissions, and premature deaths.138 The EPA expects 

that the reductions in utilization of higher-emitting units 

likely to occur during the implementation of federal plans will 

 

138 Six Common Air Pollutants. 

http://www.epa.gov/oaqps001/urbanair/
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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 greenhouse gas levels and providing 

strong leadership to encourage meaningful reductions by 

countries across the globe, this rule is a significant step to 

address health and economic impacts of climate change that will 

fall disproportionately on vulnerable communities. By reducing 

millions of tons of conventional air pollutants, this proposed 

rule will lead to better air quality and improved health in 

those communities. In the comment period for the CPP, we heard 

from many commenters who recognize and welcome those benefits. 

There are other ways in which the actions that result from 

this rulemaking may affect overburdened communities in positive 

or potentially adverse ways and we also heard about these from 

commenters. 
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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, 

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 
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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, environmental justice 

organizations, faith-based organizations, public health 

organizations, and others. This input has informed this final 

rulemaking and prompted the EPA to consider other steps that the 

agency can take in the short and long term to assist states and 

stakeholders to consider environmental justice and impacts to 

communities in plan development and implementation. 

It has also prompted us to work with our federal partners 

to make sure that communities have information on federal 

resources available to assist them. We describe these resources 

below, as well as resources that the EPA will be providing to 

assist communities in accessing EE/RE and financial assistance 

programs. 
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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.139

The EPA understands that, in order to prevent disproportionately 

high and adverse human health or environmental effects on these 

communities, both the agency and communities must have 

information on the communities living near facilities, including 

demographic data, and that accessing and using census data files 

requires expertise that some community groups may lack. 

Therefore, the EPA used census data from the American Community 

Survey (ACS) 2008-2012 to conduct a proximity analysis that can 

be used by communities as they engage with the agency throughout 

 

139 The proximity analysis was conducted using the EPA’s 

environmental justice mapping and screening tool, EJSCREEN.
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the comment period of this rulemaking. The analysis and its 

results are presented in the EJ Screening Report for the Clean 

Power Plan, which is located in the docket for this rulemaking 

at EPA-HQ-OAR-2015-0199. 

The proximity analysis provides detailed demographic 

information on the communities located within a 3-mile radius of 

each affected power plant in the United States. 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 environmental justice 

considerations, we use the terms “vulnerable” or “overburdened” 

when referring to these communities. Our intent is for these 

terms to be understood in an expansive sense, in order to 

capture the full scope of communities, including indigenous 

communities most often located in rural areas, that are central 

to our environmental justice and community considerations. 

As stated in the Executive Order 12898 discussion located 

in section XII.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 
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this rulemaking, the EPA will make it publicly available on its 

Clean Power Plan (CPP) Communities Portal that will be linked to 

this rulemaking’s 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://www.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 
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dates section for information on the upcoming public hearings), 

the agency will hold a national webinar for communities in the 

early stages of the comment period. The goal of this webinar 

will be to walk communities through the highlights of the 

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 
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community should be defined as eligible under this set-aside. We 

also seek comment on how much of the set-aside should be 

designated as targeted at over-burdened communities. We also 

request comment on whether the methods of approval and 

distribution of allowances to projects that benefit low-income 

communities should differ, and if so, in what manner, from the 

methods that are proposed to apply to other RE projects. 

As discussed below, there are also many federal programs 

that can help low-income populations access the benefits of 

renewable energy, 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 
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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 

assistance to communities affected by changes in the coal 

industry and the utility power sector.140 

D. Federal Programs and Resources Available to Communities 

A. Federal Programs and Resources Available to Communities 

Federal agencies have a history of bringing EE and 

renewable energy to low-income communities. Earlier this summer, 

the Administration announced a new initiative to scale up access 

to solar energy and cut energy bills for all Americans, in 

particular low- and moderate-income communities, and to create a 

more inclusive solar workforce. As part of this new initiative, 

the U.S. Department of Energy (DOE), the U.S. Department of 

Housing and Urban Development (HUD), U.S. Department of 

Agriculture (USDA), and the EPA launched a National Community 

Solar Partnership to unlock access to solar energy for the 

nearly 50 percent of households and businesses that are renters 

or do not have adequate roof space to install solar systems, 

with a focus on low- and moderate- income communities. The 

 

140 http://www.epa.gov/power/.
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Administration also set a goal to install 300 megawatts (MW) of 

renewable energy 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 renewable energy. To 

continue enhancing employment opportunities in the solar 

industry for all Americans, AmeriCorps is providing funding to 

deploy solar energy and create jobs in underserved communities, 

and DOE is working to expand solar energy education and 

opportunities for job training. 

These recent announcements build on the many existing federal 

programs and resources available to improve EE and accelerate the 

deployment of renewable energy in vulnerable communities. Some 

examples of these resources include: the Department of Energy’s 

Weatherization Assistance Program, Health and Human Service’s Low 

Income Home Energy Assistance Program, the Department of 

Agriculture’s Energy Efficiency and Conservation Loan Program, 

High Cost Energy Grant Program, and the Rural Housing Service’s 

Multi-Family Housing Program. 

HUD supports EE improvements and the deployment of 

renewable energy on affordable housing through its Energy 

Efficient Mortgage Program, Multifamily Property Assessed Clean 
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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 renewable energy development and EE in low-income 

communities, including the New Markets Tax Credit Program and 

the Low-Income Housing Tax Credit. The EPA’s RE-Powering 

America’s Land Initiative promotes the reuse of potentially 

contaminated lands, landfills and mine sites – many of which are 

in low-income communities – for renewable energy through a 

combination of tailored redevelopment tools for communities and 

developers, as well as site-specific technical support. The 

EPA’s Green Power Partnership is increasing community use of 

renewable electricity across the country and in low-income 

communities. The EPA partners with EE programs throughout the 

country that leverage ENERGY STAR to deliver broad consumer 

energy-saving benefits, of particular value to low-income 

households who can least afford high energy bills. ENERGY STAR 

also works with houses of worship to reduce energy costs – 

savings that can then be repurposed to their community mission, 

including programs and assistance to residents in low-income 

communities. The EPA will be working with these federal partners 

and others to ensure that states and vulnerable communities have 

access to information on these programs and their resources. 
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The federal government also has a number of programs to 

expand employment opportunities in the energy sector, including 

for underserved populations. Examples of these include HUD, DOE, 

and the Department of Education’s “STEM, Energy, and Economic 

Development” program; DOE’s Diversity in Science and Technology 

Advances National Clean Energy in Solar (DISTANCE-Solar) 

Program; Grid Engineering for Accelerated Renewable Energy 

Deployment (GEARED); the Department of Labor’s Trade Adjustment 

Assistance Community College and Career Training (TAACCCT), 

Apprenticeship USA Advancing Apprenticeships in the Energy 

Field, Job Corps Green Training and Greening of Centers, and 

YouthBuild; and the EPA’s Environmental Workforce Development 

and Job Training (EWDJT) program. 

E. Co-Pollutants 

Air quality in a given area is affected by emissions from 

nearby sources and may be influenced by emissions that travel 

hundreds of miles and mix with emissions from other sources.141

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 

 

141 76 FR 48348. 
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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.142 Thus, localized 

increases in NOx emissions may well be more than offset by NOx

decreases elsewhere in the region that produce a net improvement 

in ozone and particulate concentrations across the area. 

Another effect of the final CO2 emission standards for 

affected existing fossil fuel-fired EGUs may be increased 

utilization of other, unmodified EGUs - in particular, high 

efficiency gas-fired EGUs - with relatively low GHG emissions 

per unit of electrical output. These plants may operate more 

hours during the year and could emit pollutants, including 

pollutants whose environmental effects would be localized and 

regional rather than global as is the case with GHG emissions. 

Changes in utilization already occur in response to energy 

demands and evolving energy sources, but the final CO2 emission 

standards for affected existing fossil fuel-fired EGUs can be 

expected to cause more such changes. Increased utilization of 

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 

 

142 76 FR 48347. 
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or daily emissions generally would not change; however, 

increased utilization may make periods of relatively high 

concentrations more frequent. It should be noted that the gasfired sources likely to be dispatched more frequently have very 

low emissions of primary PM, SO2, and HAP per unit of electrical 

output and that they must continue to comply with other CAA 

requirements that directly address the conventional pollutants, 

including federal emission standards, rules included in state 

implementation plans, and conditions in title V operating 

permits, in addition to the guidelines in this final rulemaking. 

Therefore, local (or regional) air quality for these pollutants 

is not likely to be significantly affected. For natural gasfired EGUs, the EPA found that regulation of HAP emissions “is 

not appropriate or necessary because the impacts due to HAP 

emissions from such units are negligible based on the results of 

the study documented in the utility RTC.”143 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 

 

143 65 FR 79831. 
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predict NOx emissions from a NGCC unit to be approximately 10 

times lower than a subcritical or supercritical coal-fired 

boiler.144 Many, although not all, NGCC units are also very well 

controlled for emissions of NOx through the application of after 

combustion controls such as selective catalytic reduction. 

F. Assessing Impacts of Federal Plan Implementation 

It is important to the EPA that the implementation of 

federal plans be assessed in order to identify whether they 

cause any adverse impacts on communities already overburdened by 

disproportionate environmental harms and risks. The EPA will 

conduct its own assessment during the implementation phase of 

this rulemaking to determine whether the implementation of 

federal plans and other air quality rules are, in fact, reducing 

emissions and improving air quality in all areas and, or whether 

there are localized air quality impacts that need to be 

addressed under the Clean other CAA authorities. 

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 

 

144 “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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training will include guidance in accessing the publicly 

available information that sources and states currently report 

that can help with ongoing assessments of federal plan impacts. 

For example, unit-specific emissions data and air quality 

monitoring data are readily available. This information, 

together with the assessment that the EPA will conduct in the 

implementation phase of this rulemaking will enable the agency 

and communities to monitor any disproportionate emissions that 

may result in adverse impacts and address them. 

G. The EPA’s Continued Engagement 

The EPA is committed to helping ensure that this action 

will not have disproportionate adverse human health or 

environmental effects on vulnerable communities. Throughout the 

implementation phase of this rulemaking, the agency will 

continue to provide trainings and resources to assist 

communities and as they engage with the agency. The EPA, through 

its outreach efforts during the comment period, will continue to 

solicit feedback from communities on what they would like 

additional trainings and resources on. 

As described above, the EPA will assess the impacts of this 

rulemaking during its implementation. The EPA will house this 

assessment, along with the proximity analysis and other 

information generated throughout the implementation process, on 
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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.145 A more detailed 

discussion concerning the application of Executive Order 12898 

in this rulemaking can be found in section XI.J of this 

preamble. A summary of the EPA’s interactions with communities 

is in the EJ Screening Report for the Clean Power Plan, 

available in the docket of this rulemaking. Furthermore, the 

EPA’s responses to public comments, including comments received 

from communities, are provided in the response to comments 

 

145 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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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) emission guidelines for 

the control of CO2. Actions taken to comply with the guidelines 

will also reduce the emissions of directly-emitted PM2.5, SO2 and 
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NOX. The benefits associated with these PM2.5, SO2 and NOX

reductions are referred to as co-benefits, as these reductions 

are not the primary objective of this rule. 

The Regulatory Impact Analysis (RIA) for this proposal 

analyzed two implementation scenarios, which we term the “ratebased 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 
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assumed to be achieved under the federal plan or model trading 

rules. 

The EPA has used the social cost of carbon estimates 

presented in the Technical Support Document: Technical 

Update of the Social Cost of Carbon for Regulatory Impact 

Analysis Under Executive Order 12866 (May 2013, Revised 

July 2015) (“current TSD”) to analyze CO2 climate impacts of 

this rulemaking. We refer to these estimates, which were 

developed by the U.S. government, as “SC-CO2 estimates.” The 

SC-CO2 is an estimate of the monetary value of impacts 

associated with a marginal change in CO2 emissions in a 

given year. The four SC-CO2 estimates are associated with 

different discount rates (model average at 2.5 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 rate-based approach, the air pollution 
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health co-benefits in 2020 are estimated to be $0.7 billion 

to $1.8 billion (2011$) for a 3 percent discount rate and 

$0.64 billion to $1.7 billion (2011$) for a 7 percent 

discount rate. For the mass-based approach, the air 

pollution health co-benefits in 2020 are estimated to be 

$2.0 billion to $4.8 billion (2011$) for a 3 percent 

discount rate and $1.8 billion to $4.4 billion (2011$) for 

a 7 percent discount rate. The annual compliance costs 

estimated by IPM and inclusive of DS-EE program and

participant costs and MRR costs in 2020, are approximately 

$2.5 billion for the rate-based approach and $1.4 billion 

for the mass-based approach (2011$). The quantified net 

benefits (the difference between monetized benefits and 

compliance costs) in 2020 are estimated to range from $1.0 

billion to $2.1 billion (2011$) for the rate-based approach 

and from $3.9 billion to 6.7 billion (2011$) for the massbased 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 
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estimated to be $7.4 billion to $18 billion (2011$) for a 3 

percent discount rate and $6.7 billion to $16 billion (2011$) 

for a 7 percent discount rate. For the mass-based approach, the 

air pollution health co-benefits in 2025 are estimated to be 

$7.1 billion to $17 billion (2011$) for a 3 percent discount 

rate and $6.5 billion to $16 billion (2011$) for a 7 percent 

discount rate. The annual compliance costs estimated by IPM and 

inclusive of DS-EE program and participant costs and MRR costs 

in 2025, are approximately $1.0 billion for the rate-based 

approach and $3.0 billion for the mass-based approach (2011$). 

The quantified net benefits (the difference between monetized 

benefits and compliance costs) in 2025 are estimated to range 

from $17 billion to $27 billion (2011$) for the rate-based 

approach and $16 billion to $26 billion (2011$) for the massbased approach, using a 3 percent discount rate (model average). 

The EPA estimates that, in 2030, the proposal will yield 

monetized climate benefits (in 2011$) of approximately $20 

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 
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pollution health co-benefits in 2030 are estimated to be $12 

billion to $28 billion (2011$) for a 3 percent discount rate and 

$11 billion to $26 billion (2011$) for a 7 percent discount 

rate. The annual compliance costs estimated by IPM and inclusive 

of DS-EE program and participant costs and MRR costs in 2030, 

are approximately $8.4 billion for the rate-based approach and 

$5.1 billion for the mass-based approach (2011$). The quantified 

net benefits (the difference between monetized benefits and 

compliance costs) in 2030 are estimated to range from $26 

billion to $45 billion (2011$) for the rate-based approach and 

from $26 billion to $43 billion (2011$) for the mass-based 

approach, using a 3 percent discount rate (model average). 

Table 18 and Table 19 of this preamble provide the 

estimates of the climate benefits, health co-benefits, 

compliance costs and net benefits of the proposal for rate-based 

and mass-based federal plan approaches, respectively. 

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 
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5% discount 

rate 

$0.80 $3.1 $6.4 

3% discount 

rate 

$2.8 $10 $20 

2.5% 

discount 

rate 

$4.1 $15 $29 

95th 

percentile 

at 3% 

discount 

rate 

$8.2 $31 $61 

 Air Quality Co-benefits Discount Rate 

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

Air Quality 

Health Cobenefitsc

$0.70 

to $1.8 

$0.64 

to $1.7

$7.4 

to $18

$6.7 to 

$16 

$14 to 

$34 

$13 to 

$31 

Compliance 

Costsd $2.5 $1.0 $8.4 

Net 

Benefitse

$1.0 to 

$2.1 

$1.0 to 

$2.0 

$17 to 

$27 

$16 to 

$25 

$26 to 

$45 

$25 to 

$43 

NonMonetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 and SO2

Reductions in mercury deposition 

Ecosystem benefits associated with reductions in 

emissions of NOX, SO2, PM, and mercury 

Visibility impairment 

a All are rounded to two significant figures, so figures may not 

sum. 

b The climate benefit estimate in this summary table reflects 

global impacts from CO2 emission changes and does not account for 
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changes in non-CO2 GHG emissions. Also, different discount rates 

are applied to SC-CO2 than to the other estimates because CO2

emissions are long-lived and subsequent damages occur over many 

years. The benefit estimates in this table are based on the 

average SC-CO2 estimated for a 3 percent discount rate. However, 

we emphasize the importance and value of considering the full 

range of SC-CO2 values. As shown in the RIA, climate benefits are 

also estimated using the other three SC-CO2 estimates (model 

average at 2.5 percent discount rate, 3 percent, and 5 percent; 

95th percentile at 3 percent). The SC-CO2 estimates are yearspecific and increase over time. 

c The air pollution health co-benefits reflect reduced exposure 

to PM2.5 and ozone associated with emission reductions of SO2 and 

NOX. The range reflects the use of concentration-response 

functions from different epidemiology studies. The co-benefits 

do not include the benefits of reductions in directly emitted 

PM2.5. These additional benefits would increase overall benefits 

by a few percent based on the analyses conducted for the Clean 

Power Plan proposed rule. The reduction in premature fatalities 

each year accounts for over 98 percent of total monetized cobenefits from PM2.5 and ozone. These models assume that all fine 

particles, regardless of their chemical composition, are equally 

potent in causing premature mortality because the scientific 

evidence is not yet sufficient to allow differentiation of 

effect estimates by particle type. 

d 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. 

Table 19. Summary of the Monetized Benefits, Compliance Costs, 

and Net Benefits for the Proposal in 2020, 2025 and 2030 
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Under the Mass-Based Federal Plan Approach [Billions of 2011$]a

 Mass-Based Approach 

2020 2025 2030 

Climate 

Benefitsb 

5% discount 

rate 

$0.9 $3.6 $6.4 

3% discount 

rate 

$3.3 $12 $20 

2.5% 

discount 

rate 

$4.9 $17 $29 

95th 

percentile 

at 3% 

discount 

rate 

$9.7 $35 $60 

 Air Quality Co-benefits Discount Rate 

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

Air Quality 

Health Cobenefitsc

$2.0 to 

$4.8 

$1.8 to 

$4.4 

$7.1 

to $17

$6.5 to 

$16 

$12 to 

$28 

$11 to 

$26 

Compliance 

Costsd

$1.4 $3.0 $5.1 

Net 

Benefitse

$3.9 to 

$6.7 

$3.7 to 

$6.3 

$16 to 

$26 

$15 to 

$24 

$26 to 

$43 

$25 to 

$40 

NonMonetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 and SO2

Reductions in mercury deposition 

Ecosystem benefits associated with reductions in 
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emissions of NOX, SO2, PM, and mercury 

Visibility improvement 

a All are rounded to two significant figures, so figures may not 

sum. 

b The climate benefit estimate in this summary table reflects 

global impacts from CO2 emission changes and does not account for 

changes in non-CO2 GHG emissions. Also, different discount rates 

are applied to SC-CO2 than to the other estimates because CO2

emissions are long-lived and subsequent damages occur over many 

years. The benefit estimates in this table are based on the 

average SC-CO2 estimated for a 3 percent discount rate. However, 

we emphasize the importance and value of considering the full 

range of SC-CO2 values. As shown in the RIA, climate benefits are 

also estimated using the other three SC-CO2 estimates (model 

average at 2.5 percent discount rate, 3 percent, and 5 percent; 

95th percentile at 3 percent). The SC-CO2 estimates are yearspecific and increase over time. 

c The air pollution health co-benefits reflect reduced exposure 

to PM2.5 and ozone associated with emission reductions of SO2 and 

NOX. The co-benefits do not include the benefits of reductions in 

directly emitted PM2.5. These additional benefits would increase 

overall benefits by a few percent based on the analyses 

conducted for the Clean Power Plan proposed rule. The range 

reflects the use of concentration-response functions from 

different epidemiology studies. The reduction in premature 

fatalities each year accounts for over 98 percent of total 

monetized co-benefits from PM2.5 and ozone. These models assume 

that all fine particles, regardless of their chemical 

composition, are equally potent in causing premature mortality 

because the scientific evidence is not yet sufficient to allow 

differentiation of effect estimates by particle type. 

d 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 
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(model average). The RIA includes combined climate and health 

estimates based on additional discount rates. 

There are additional important benefits that the EPA could 

not monetize. Due to current data and modeling limitations, our 

estimates of the benefits from reducing CO2 emissions do not 

include important impacts like ocean acidification or potential 

tipping points in natural or managed ecosystems. Unquantified 

benefits also include climate benefits from reducing emissions 

of non-CO2 greenhouse gases (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 
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enforceable until approved by OMB. 

This rule does not directly impose specific requirements on 

state and U.S. territory governments with affected EGUs. The 

rule also does not impose specific requirements on tribal 

governments that have affected EGUs located in their area of 

Indian country. This rule does impose specific requirements on 

EGUs located in states, U.S. territories or areas of Indian 

country. 

The information collection activities in this proposed rule 

are consistent with those activities defined under the Carbon 

Pollution Emission Guidelines for Existing Stationary Sources: 

Electric Utility Generating Units (79&&&XX FR 34830XXX; the 

Clean Power Plan) finalized on &&&July 31, 2015. The information 

collection requirements in this proposed rule have been 

submitted for approval to the Office of Management and Budget 

(OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. 

The Information Collection Request (ICR) document prepared by 

the EPA has been assigned EPA ICR number 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 
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already be subject to under the authorities of CAA parts 75 and 

98. OMB has previously approved the information collection 

requirements contained in the existing part 75 and 98 

regulations (40 CFR part 75 and 40 CFR part 98) under the 

provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et 

seq. and has assigned OMB control numbers 2060–0626 and 2060– 

0629, respectively. Apart from certain reporting costs based on 

requirements in the NSPS General Provisions (40 CFR part 60, 

subpart A), which are mandatory for all owners/operators subject 

to CAA section 111 national emission standards, there are no new 

information collection costs, as the information required by 

this proposed rule is already collected and reported by other 

regulatory programs. The recordkeeping and reporting 

requirements are specifically authorized by CAA section 114 (42 

U.S.C. 7414). All information submitted to the EPA pursuant to 

the recordkeeping and reporting requirements for which a claim 

of confidentiality is made is safeguarded according to agency 

policies set forth in 40 CFR part 2, subpart B. 

Although EPA cannot determine at this time how many

affected EGU respondents will submit information under the 

federal plan, EPA has estimated an “upper bound” burden estimate 

for this ICR that estimates burden should every affected EGU 

read and understand the rule. This is the only potential 
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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’s obligation to respond: Not applicable, no 

responses are required during the period covered by the ICR. 

Estimated number of respondents: Unknown at this time, but 

have assumed all affected entities are respondents for an upper 

bound estimate. 

Frequency of response: None, no responses are required 

during the period covered by the ICR. 

Total estimated burden: 17,133 hours (per year). Burden is 

defined at 5 CFR 1320.3(b). 

Total estimated cost: $1,706,501 (per year) 

An agency may not conduct or sponsor, and a person is not 

required to respond to, a collection of information unless it 

displays a currently valid OMB control number. The OMB control 

numbers for the EPA’s regulations in 40 CFR are listed in 40 CFR 

part 9. 

Submit your comments on the agency’s need for this 

information, the accuracy of the provided burden estimates and 
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any suggested methods for minimizing respondent burden to the 

EPA using the docket identified at the beginning of this rule. 

You may also send your ICR-related comments to OMB’s Office of 

Information and Regulatory Affairs via email to 

oria_submissions@omb.eop.gov, Attention: Desk Officer for the 

EPA. Since OMB is required to make a decision concerning the ICR 

between 30 and 60 days after receipt, OMB must receive comments 

no later than [insert date 30 days after date of publication in 

the Federal Register]. The EPA will respond to any ICR-related 

comments in the final rule. 

C. Regulatory Flexibility Act (RFA) 

Pursuant to section 603 of the RFA, the EPA prepared an 

initial regulatory flexibility analysis (IRFA) that examines the 

impact of the proposed rule on small entities along with 

regulatory alternatives that could minimize that impact. The 

complete IRFA is available for review in the docket and is 

summarized here. 

[&&&Insert summary of IRFA here] 

As required by section 609(b) of the RFA, the EPA also 

convened a Small Business Advocacy Review (SBAR) Panel to obtain 

advice and recommendations from small entity representatives 

that potentially would be subject to the rule's requirements. 

The SBAR Panel evaluated the assembled materials and small-
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entity 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) 

[&&&based on preliminary analysis] 

This action contains a federal mandate under UMRA, 2 U.S.C. 

1531–1538, that may result in expenditures of $100 million or 

more for state, local and tribal governments, in the aggregate, 

or the private sector in any 1 year. Accordingly, the EPA has 
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prepared the written statement required under section 202 of 

UMRA that is included in the docket for this action and briefly 

summarized here. [&&&Insert a concise summary of the written 

statement including a brief description of the intergovernmental 

consultation.] 

This action may significantly or uniquely affect small 

governments. The EPA consulted with small governments concerning 

the regulatory requirements that might significantly or uniquely 

affect them.

E. Executive Order 13132: Federalism 

[&&&based on preliminary analysis] 

 Under Executive Order 13132, the EPA may not issue an 

action that has federalism implications, that imposes 

substantial direct compliance costs, and that is not required by 

statute, unless the federal government provides the funds 

necessary to pay the direct compliance costs incurred by state 

and local governments, or the EPA consults with state and local 

officials early in the process of developing the proposed 

action. The EPA has concluded that this action may have 

federalism implications, because it may impose substantial 

direct compliance costs on state or local governments, and the 

federal government will not provide the funds necessary to pay 

those costs. As discussed in the supporting statement found in 
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the docket for this rulemaking, [&&& Insert text consistent with 

PRA analysis]. 

The EPA consulted with state and local officials early in 

the process of developing the Clean Power Plan EGs to permit 

them to have meaningful and timely input into its development. 

As described in the Federalism discussion in the preamble to the 

proposed standards of performance for GHG emissions from new 

EGUs (79 FR 1501, January 8, 2014), the EPA consulted with state 

and local officials in the process of developing the proposed 

standards for newly constructed EGUs. A detailed Federalism 

Summary Impact Statement (FSIS) describing the most pressing 

issues raised in pre-proposal and post-proposal comments will be 

forthcoming with the final rule, 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 
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recognized tribal governments, nor preempt tribal law. The EGU 

potentially impacted by this proposed rulemaking located on 

Indian reservations are primarily owned by private entities, 

and in one case, partially owned by an agency of the United 

States government. As a result, the tribes on whose areas of 

Indian country those units are located will not be directly 

impacted by any costs of complying with this proposed rulemaking 

incurred by the owners/operators of those units. There would 

only be tribal implications in regards to compliance costs 

associated with this proposed rulemaking in the case where a 

tribal government has an ownership interest in a potentially 

affected EGU. A tribal government could also incur costs in the 

event that it seeks and is given delegated authority to enforce 

the federal plan proposed in this rulemaking. The EPA has, 

nevertheless, offered consultation to the tribes on whose areas 

of Indian country the units are located. As part of its general 

outreach to tribes regarding this proposed rulemaking, the EPA 

received feedback from a number of tribes regarding the 

potential overall economic impact that both the proposed Clean 

Power Plan and a proposed federal 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 
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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, Arizonia. At the public hearing 

the agency received oral comments from community members 

representing a number of tribes and a number of tribal officals. 

The agency also conducted consultation with tribes in the spring 

and summer of 2015. An overview of the consultations provided as 

part of the Clean Power Plan is available in section XII.F of 

the final 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 (NTAA) and the EPA Air Policy call. Additionally, 

staff attended the National Tribal Forum conference on May 20, 
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2015 and provided an overview of the Clean Power Plan and 

explained that the agency would be proposing a federal plan. 

certification is included in the docket for this action. 

Consistent with previous rulemakings impacting the power 

sector, there is significant tribal interest in these 

rulemakings because of the potential indirect impacts that rules 

such as the Clean Power Plan and this proposed federal plan may 

have on tribes. The EPA specifically solicits additional 

feedback from tribal officials on all aspects of this proposed 

rulemaking, including whether tribes whose areas of Indian 

country contain affected EGU(s) are interested in developing 

their own plan implementing the final emission guidelines. 

Additionally, tribal stakeholders will be included in the 

outreach that the agency will be conducting with those 

communities already overburdened by pollution, which are often 

low-income communties, communities of color, , and indigenous 

communities. The actions that the agency will be 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–
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501 of the Order has the potential to influence the regulation. 

This action is not subject to EO 13045 because it does not 

involve decisions on environmental health or safety risks that 

may disproportionately affect children. The EPA believes that 

the CO2 emission reductions resulting from implementation of the 

proposed guidelines, as well as substantial ozone and PM2.5 

emission reductions as a cobenefit, would further improve 

children’s health. 

H. Executive Order 13211: Actions That Significantly Affect 

Energy Supply, Distribution, or Use 

This action, which is a significant regulatory action under 

EO 12866, is likely to have a significant effect on the supply, 

distribution, or use of energy. The EPA has prepared a Statement 

of Energy Effects for this action as follows. We estimate a 1 to 

2 percent change in retail electricity prices on average across 

the contiguous U.S. in 2025, and a 22 to 23 percent reduction in 

coal-fired electricity generation as a result of this rule. The 

EPA projects that utility power sector delivered natural gas 

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. 
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I. National Technology Transfer and Advancement Act (NTTAA) 

This proposed action does not involve technical standards. 

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations 

Executive Order 12898 (59 FR 7629; February 16, 1994) 

establishes federal executive policy on environmental justice. 

Its main provision directs federal agencies, to the greatest 

extent practicable and permitted by law, to make environmental 

justice part of their mission by identifying and addressing, as 

appropriate, disproportionately high and adverse human health or 

environmental effects of their programs, policies, and 

activities on minority populations and low-income populations in 

the U.S. The EPA defines environmental justice as the fair 

treatment and meaningful involvement of all people regardless of 

race, color, national origin, or income with respect to the 

development, implementation, and enforcement of environmental 

laws, regulations, and policies. The EPA has this goal for all 

communities and persons across this Nation. It will be achieved 

when everyone enjoys the same degree of protection from 

environmental and health hazards and equal access to the 

decision-making process to have a healthy environment in which 
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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 (USGCRP), the 

Intergovernmental Panel on Climate Change (IPCC), and the 

National Research Council (NRC) of the National Academies that 

the potential impacts of climate change raise environmental 
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justice 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 

populations and low-income populations in the United States.146

 

146 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, 
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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 United States. These reports find 

that certain climate change related impacts—including heat 

 

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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waves, degraded air quality, and extreme weather events—have 

disproportionate effects on low-income populations and some 

communities of color (in particular, populations defined jointly 

by ethnic/racial characteristics and geographic location), 

raising environmental justice concerns. Existing health 

disparities and other inequities in these communities increase 

their vulnerability to the health effects of climate change. In 

addition, assessment reports also find that climate change poses 

particular threats to health, well-being, and ways of life of 

indigenous peoples in the United States. 

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 renewable energy. These emission reductions will include 
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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,147 the EPA identified lowincome populations as being a vulnerable population for 

experiencing adverse health effects related to PM exposures. 

Low-income populations have been generally found to have a 

higher prevalence of pre-existing diseases, limited access to 

medical treatment, and increased nutritional deficiencies, which 

can increase this population’s susceptibility to PM-related 

effects.148 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 environmental 

justice considerations section IX of this preamble, the EPA has 

 

147 “National Ambient Air Quality Standards for Particulate Matter, 

Final Rule,” 78 FR 3086 (Jan. 15, 2013). 

148 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/ncea/cfm/recordisplay.cfm?deid=216546.
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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.149 As described in the community and environmental 

justice considerations section of this preamble the EPA also 

conducted a proximity analysis, which is available in the docket 

of this rulemaking and is discussed in section IX of this preamble. 

Additionally, as outlined in sections I and IX of this preamble 

the EPA has engaged meaningfully with communities throughout the 

development of the CPP and has devised a robust outreach strategy 

for continual engagement throughout this rulemaking. 

 

149 Guidance on Considering Environmental Justice During the 

Development of Regulatory Actions. 

http://epa.gov/environmentaljustice/resources/policy/considering

-ej-in-rulemaking-guide-final.pdf. May 2015. 
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List of Subject in 40 CFR Part 62 

Environmental protection, Administrative practice and 

procedure, Air pollution control, Intergovernmental

relations, Reporting and recordkeeping requirements. 

Dated: _________________. 

________________________ 

Gina McCarthy, 

Administrator.