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EO12866_CPP Federal Plan 2060 AS47 NPRM_2015070220150727

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 62

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

RIN 2060-AS47

Federal Plan Requirements for Greenhouse Gas Emissions from 

Electric Utility Generating Units Constructed on or Before 

January 8, 2014; Model Trading RuleRules; Amendments to 

Framework Regulations

AGENCY: Environmental Protection Agency (EPA)..

ACTION: Proposed Rule.

SUMMARY: In this action, the Environmental Protection Agency 

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

gas 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 (the Clean Power 

Plan). This proposal presents two approaches to a federal plan

for states and other jurisdictions that do not adopt and submit 

to the EPA in a timely manner an approvable plan: a rate-based 

emission trading program and a mass-based emission trading 
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program. These proposals also constitute proposed model trading 

rules that states can adopt or tailor for implementation of the 

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

congressionally mandated emission standards under the authority 

of the CAA are implemented. The proposed federal plan is related 

to but separate from the final EGs. The final EGs establish the 

best system of emission reduction (BSER) for applicable fossil

fuel-fired EGUs in the form of a standard of &&& for steam-fired 

EGUs and a standard of &&& 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 the BSER in order to achieve reductions 

in carbon dioxide (CO2) emissions in the case where a state or 

other jurisdiction does not submit an approvable plan. These CO2

reductions laid out in the final EGs will be equivalent whether 

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

also proposing enhancements to the section 111(d) framework 

regulations related to the process and timing for state plan 

submissions and EPA actions. The EPA intends to finalize both 

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

2016.

DATES: Comments. Comments must be received on or before [insert 
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date 45 days FROM DATE OFafter publication in the Federal 

Register]. 

Public Hearing. If anyone contacts the EPA by [INSERT DATE 10 

DAYS FROM DATE OF PUBLICATION IN THE FEDERAL REGISTER] 

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

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

OF THIS PROPOSED RULE IN THE FEDERAL REGISTER]. Public Hearing. 

The EPA will be holding XXX [insert number of hearings here] 

public hearings on the proposed federal plan. The hearings will 

be held to accept oral comments on the proposed federal plan. 

The hearings will be held on XXX, 2015, in XXX, XXX, 2015, in 

XXX, and XXX, 2015, in XXX. 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 www.regulations.gov: Follow 

the online instructions for submitting comments.

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

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

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

• Mail: Send your comments to: EPA Docket Center 

(EPA/DC), Environmental Protection Agency, Mailcode: 

28221T, 1200 Pennsylvania Ave., NW, Washington, DC 

20460, Attention Docket ID No. EPA-HQ-OAR-2015-0199. 
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We request that a separate copy also be sent to the 

contact person identified below (see FOR FURTHER 

INFORMATION CONTACT).

• Hand Delivery: Deliver your comments to: EPA Docket 

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

1301 Constitution Ave., NW, Washington, DC, 20004, 

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

deliveries are accepted only during the 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 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 www.regulations.gov or email. The 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 

www.regulations.gov, your email address will be automatically 

captured and included as part of the comment that is placed in 
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the public docket and made available on the Internet. If you 

submit an electronic comment, the EPA recommends that you 

include your name and other contact information in the body of 

your comment and with any disk or CD-ROM you submit. If the EPA 

cannot read your comment due to technical difficulties and 

cannot contact you for clarification, the EPA may not be able to 

consider your comment. Electronic files should avoid the use of 

special characters, any form of encryption and be free of any 

defects or viruses.

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

hearings will be held to accept oral comments on the proposed 

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

XXX, 2015, in XXX, and XXX, 2015, in XXX. The hearings will 

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

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

1:00 p.m. and a dinner break from 5:00 p.m. to 6:00 p.m. To 

register for the hearing, please use the online registration 

form available at 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 hearing will be 

XXX, 2015. Additionally, requests to speak will be taken the day 

of the hearing at the hearing registration desk, although 

preferences on speaking times may not be able to be fulfilled. 
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Please note that registration requests received before the 

hearing will be confirmed by the EPA via email. We cannot 

guarantee that we can accommodate all timing requests and will 

provide requestors with the next available speaking time, in the 

event that there requested time is taken. Please note that in 

the time outlined in the confirmation email received will be the 

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

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

of a translator or special accommodations such as audio 

description, we ask that you pre-register for the hearing 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/cleanpowerplanPublic Hearing: If a public 

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

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

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

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

hearing concerning this proposed rule by [INSERT DATE 10 DAYS 

FROM DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL 

REGISTER], the hearing will be cancelled without further notice.

. While the EPA expects the hearing to go forward as set forth 

above, we ask that you monitor our Web site or contact XXXX at 
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(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 hearing will provide interested parties the opportunity to 

present data, views, or arguments concerning the proposed 

action. The EPA will make every effort to accommodate all 

speakers who arrive and register. The EPA may ask clarifying 

questions during the oral presentations, but will not respond to 

the presentations at that time. Written statements and 

supporting information submitted during the comment period will 

be considered with the same weight as oral comments and 

supporting information presented at the public hearing. Verbatim 

transcripts of the hearing and written statements will be 

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

hearing 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, 
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Louisiana, Maine, Massachusetts, Minnesota, Montana, New York, 

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

additional form of identification to enter the federal building. 

Acceptable alternative forms of identification include: Federal 

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

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

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

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

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

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

and demonstrations will not be allowed on federal property for 

security reasons. 

Attendees will be asked to go through metal detectors. To 

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

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

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

devices from their carrying case and place in provided bins for

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

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

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

of the guard if identified for secondary screening. Additionally, 

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

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

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

registration desk.

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

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

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

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

in the docket are listed in the www.regulations.gov index. 

Although listed in the index, some information is not publicly 

available, e.g., CBI or other information whose disclosure is 

restricted by statute. Certain other material, such as 

copyrighted material, will be publicly available only in hard 

copy form. Publicly available docket materials are available 

either electronically at www.regulations.gov or in hard copy at 

the EPA Docket Center EPA/DC, EPA WJC West Building, Room 3334, 

1301 Constitution Ave., NW, Washington, DC. The Public Reading 

Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, 

excluding holidays. The telephone number for the Public Reading 

Room is (202) 566-1744, and the telephone number for the EPA 

Docket Center is (202) 566-1742.

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

Incineration Group, Sector Policies and Programs Division 

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

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

SUPPLEMENTARY INFORMATION: 

Acronyms and Abbreviations. The following acronyms and 

abbreviations are used in this document.

AG Attorney General

ANSI American National Standards Institute

ASME American Society of Mechanical Engineers

ASTM American Society of Testing and Materials

CAA Clean Air Act

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

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

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
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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

RFA Regulatory Flexibility Act

RGGI Regional Greenhouse Gas Initiative

SBA Small Business Administration

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

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
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C. Affected EGUs

D. Compliance Schedule

E. Addressing Reliability Concerns

F. Worker Certification

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

H. Implications for Other EPA Programs and Rules

I. Administrative Appeals Process

J. Consistency of Program Structure with Clean Air Act Authority

IV. Rate-based Implementation Approach 

A. Overview

B. Rate Goals

C. Crediting Mechanism

D. ERC Tracking and Compliance Operations

E. Federal Plan and State Plan Interactions

V. Mass-based Implementation Approach 

A. Trading Program Overview 

B. Statewide Mass-based Emissions Goals

C. Compliance Timing and Allowance Banking

D. Initial Distribution of Allowances

E. State-determined Allowance Distribution

F. Treatment of States Entering or Exiting the Trading Program

G. Allowance Tracking, Compliance Operations, and Penalties

H. Emissions Monitoring and Reporting Requirements

VI. Implementation of the Federal Plan and Delegation

A. Delegation of the Federal Plan and Retained Authorities

B. Mechanisms for Transferring Authority

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
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E. Update to Deadlines for EPA Actions

F. Proposed Interpretation regarding Existing Sources that 

Modify or Reconstruct

G. Separate Finalization of these Changes

VIII. Impacts of this Action

A. Endangered Species Act

B. What are the Air Impacts? 

C. What are the Energy Impacts? 

D. What are the Compliance Costs?

E. What are the Economic and Employment Impacts? 

F. What are the Benefits of the Proposed Action? 

IX. Community and Environmental Justice Considerations

A. Proximity Analysis

B. Community Engagement in This Rulemaking Process

C. Providing Communities with Access to Additional Resources

D. Federal Programs and Resources Available to Communities

E. Co-Pollutants

F. Assessing Impacts of Federal Plan Implementation

G. The EPA’s Continued Engagement

X. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and 

Executive Order 13563: Improving Regulation and Regulatory 

Review 

B. Paperwork Reduction Act (PRA)

C. Regulatory Flexibility Act (RFA)

D. Unfunded Mandates Reform Act (UMRA)

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 
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Environmental Justice in Minority Populations and Low-Income 

Populations

I. General Information

A. Executive Summary 

In the Clean Air Act, Congress created a partnership 

between the Environmental Protection AgencyEPA and the states.

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

Environmental Protection Agency (EPA) EPA establishes emission 

targetsperformance levels based on its determination of the best 

system of emission reduction (BSER) for existing sources of air 

pollution and provides guidelines for state plans to apply the

emission targetsstandards of performance to their sources. that 

meet the BSER level of performance. The EPA has promulgated 

these Emission Guidelines (EGs) under section 111(d), which sets 

source-level CO2 emission performance rates for the electric 

generating units (EGUs) at certain large fossil fuel-fired power 

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

sources in state plans. The EGs are designed to maximize the 

flexibility of both states and affected EGUs in meeting CO2

emissions performance rates. While states may impose the 

emission rates directly on their affected EGUs, states also have 

the option of submitting more tailored plans that meet statespecific emissions goals. The EGs also provide flexibility by 
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allowing for emissions trading and multi-state compliance 

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

to be achievable for these sources was based on its 

determination of what constituted the best system of emission 

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

EGs. 

At this point, the responsibility shifts to the states, who

can submit plans to achieve these emission performance levels

for EPA approval, or, in lieu of plans, initial plan submittals, 

by August 31, 2016. While it has been the EPA’s longstanding 

view that the statute identifies states as the preferred 

implementers of CAA programs, the agency makes clear in the EGs 

that states cannot 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. 
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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 large emitting fossil-fuel fired power 

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

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

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

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

Both proposed approaches to the federal plan would require

affected EGUs to meet emission standards set using the CO2

emission performance rates in the EGs. The federal plan will 

achieve the same levels of emissions performance as required of 

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

federal plan for 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 notice 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 
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plan and the corresponding model trading rule is identical., 

except as indicated otherwise within the text of the model rule

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

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

resources than is being proposed in the federal plan).

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

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

state fails todoes not submit an approvable plan by the 

deadlines specified in the final EGs and the EPA takes action 

finding that the state has failed to submit a plan, or 

disapproving a submitted plan because it does not meet the 

requirements of the EGs.1 Indeed, states may simply choose to 

 

1 For simplicity, at times this notice may refer to the co-proposed 

federal plans as “the federal plan.” (It may refer to the model 

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

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

when referring to this proposed federal plan also is intended to 

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

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

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

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

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

rule promulgated multiple FIPs. 
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accept a federal plan for their sources rather than undertake 

the development of a plan of their own by not submitting a state 

plan. Under today’s proposalthis proposed rule, a federal plan 

promulgated for a particular state would take the form of either 

the mass-based model trading rule or the rate-based model 

trading rule. The EPA is strongly considering takingcurrently 

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

promulgates a federal plan, and we are inviting comment ongiven 

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

following section of this. preamble.. We also invite comment on 

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

should be selected if we opt to finalize a single approach.

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

opportunity as possible to set their own course for carrying out 

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

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

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

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

&&&,VI.A, states may take a full or partial delegation of 

administrative aspects of the federal plan in order to become 

the primary implementers. And as discussed in section 

&&&,Sections V.E and VII.A, states may submit partial state 
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plans in order to take over the implementation of a portion of a 

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

agency proposes to allow states to submit partial state plans to 

replace the federal plan allowance-distribution provisions with 

their own allowance-distribution provisions, similar to the 

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

in states in which the affected EGUs are operating under a 

federal plan, the agency recognizes that states may adopt 

complementary measures outside of CAA programming to facilitate 

compliance and lower costs that could benefit power generators 

and consumers, directly or indirectly.

A state program that adheres to the model trading rule 

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, 

 

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 
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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 serves as a mechanism to create larger trading markets 

since consistency with the federal plan allows trading across 

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

trading region is likely to result in lower overall costs. These 

and other aspects of the model trading rules and federal plan 

provide additional support for this rule as proposed. Thus, the 

proposed rule would ensure that congressionally mandated 

emission standards under authority of section 111 of the CAA are 

implemented, either by the states in the first instance, or by 

the EPA where needed.

The agency is proposing a finding that it is necessary or 

appropriate to implement a 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 

 

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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tribal plan to implement CAA programs, including programs under 

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, we are 

proposing a necessary or appropriate finding. 

This notice also proposes certain enhancements to the 

process and timing for state submittals and EPA action in the 

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

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

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

under the Clean Power Plan and other section 111(d) rules. These 

changes clarify the availability of certain procedural 

mechanisms similar to those available under 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 
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is subject to a section 111(b) standard moves an existing source 

out of a section 111(d) program. These proposed changes are 

discussed in &&&Section VII. 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 the reliability of the electrical grid, and, importantly,

on. The agency gave extensive consideration to impacts on 

vulnerable communities, particularly low-income communities and,

communities of color. , and indigenous communities. These 

considerations are generally discussed in &&§ions III, VIII, 

IX, and X.

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, 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 notice how it proposes to take into 

consideration the “remaining useful lives” of affected EGUs in 
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the design of the proposed federal plan, as discussed below in 

section &&&III.H.

The agency considered the impacts this action could have on 

the electricity grid and developed options for compliance that 

are cost-effective and ensure the reliability of electrical 

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

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

two approaches (i.e., rate- andbased or mass-based trading)

enables the EPA and the states to create a level of flexibility

for affected EGUs that allows owners and operators to determine 

the best way to achieve emissions reductions, at the EGU-, 

state-, multi-state-, regional-, or national level. As a result, 

compliance strategies can mirror, or be integrated with, the 

ongoing operations of the current electricity grid as it 

continues to serve its primary critical function of ensuring an 

uninterrupted supply of affordable and reliable electricity. 

This flexibility is especially valuable whenever the need to 

address specific reliability concerns arises. It allows owners 

and operators of reliability-critical EGUs to continue to meet 

their compliance obligations while operating to maintain 

electric reliability.

We also reviewed impacts that this action could have on the 

environment and the need to ensure environmental integrity of 
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the program as well as avoid unintended environmental impacts. 

We took measures to ensure that the reductions in carbon 

emissions this plan will achieve are real, and not just 

apparent. As in the EGs, in both the rate- and mass-based

approaches, the EPA has incorporated components to address the 

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

trading program could incentivize shifting generation from 

existing units in ways that would result in more CO2 emissions 

than would otherwise be expected, or that undermine the purpose 

of the 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 Guidelines, the EPA emphasized the importance 
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of state actions to ensure that in developing their respective 

compliance plans the states addressed the concerns and 

priorities of overburdenedvulnerable communities. In the process 

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

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

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

the American public on this proposed rulemaking, we will also be 

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

regions on this proposed rulemaking for overburdened

communities. The goal of these outreach activities is to provide 

communities with the information they need to understand how the 

proposed rulemaking will potentially impact their respective 

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

in helping overburdened communities engage the EPA during our 

comment period, as well as with their states during the state 

plan development process. We will also be providing other 

outreach and support activities for overburdenedvulnerable

communities, which are outlined in the community and 

environmental justice considerations section IX.B of this 

preamble.

B. Organization and Approach for this Proposed Rule

In today’sthis action, the EPA is proposing a federal plan

to implement the Clean Power Plan EGs for affected fossil fuel-
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fired EGUs operating in states that do not have approved state 

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

approaches to a federal plan to implement the Clean Power Plan 

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

approach. While establishing emission standards for affected 

EGUs that would be directly enforceable against the owners and 

operators of the source, both approaches would grant EGUs 

substantial flexibility in meeting their compliance obligations. 

For this reason, among others, these proposed approaches also 

serve as two proposed model trading rules that states may adopt 

or tailor in designing their own plans.

The EGs provide that states have until August 31, 2016 (or 

later, if extensions are granted) to submit state plans, and the 

EPA does not intend to finalize and implement the federal plan

for any states prior to the agency’s action of determining a 

failure to submit a state plan or disapproving a state plan. At 

the same time, in order to support states’ consideration of 

adoption of one of the model trading rules as an approvable 

state plan, the agency intends to finalize either or both model 

rule options presented in today’s proposalthis proposed rule by 

summer 2016, prior to the deadline for state submittals.

The EPA is currently considering finalizing onlyintends to

finalize a single approach — i.e., either a rate-based or a 
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mass-based approach — in all promulgated federal plans for 

particular states in order to enhance the consistency of the 

federal trading program, achieve economies of scale through a 

single, broad trading program, ensure efficient administration 

of the program, and simplify compliance options for affected 

EGUs. However, the EPA recognizes thatWe 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. Therefore, we are inviting 

comment on whether the agency should The EPA recognizes that it 

remains potentially possible to finalize only onea different

approach for all states that may become subject to theto a

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

rate-based or mass-based approach should be selected based on 

the uniquein some circumstances of each state, but believes that 

in general, and consistent with prior federal trading programs 

such as CSAPR, creating a single, broad program has the most 

advantages. 

The stringency of the proposed federal plan is the same as 

the CO2 emission performance rates established for affected EGUs

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

the CO2 emission performance rates through the application of the 
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best system of emission reduction (BSER). In the EGs, the EPA 

has taken final action on the BSER for CO2 emissions from 

existing fossil fuel-fired EGUs. Any comments on today’sthis 

proposed rule relating to the BSER, its stringency, rationale, 

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

will be beyond the scope of this action.3

The state goals, stated as both an aggregated emission 

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

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

established for states in the final EGs. The emission standards 

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

federal plan are derived directly from these numbers.

1. The Rate-based Approach

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

emissions trading program. In a rate-based program, affected 

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

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

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

sufficient number of emission rate credits (ERC), each 

 

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

facilities subject to a 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 &&§ion III.G below.
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representing a zero-emitting megawatt hour (MWh), to bring their 

rate of emissions into compliance. ERCs may be generated by 

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

and recognition process that the EPA will administer. ERCs may 

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

the Preamble.

2. The Mass-based Approach

The second approach to a federal plan that the EPA is 

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

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

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

the affected EGUs in that each state according to the massequivalency formula in the EGs. The EPA would initially 

distribute the allowances within each state budget – less 

twothree proposed allowance set-asides – to the affected EGUs

based on their historic 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 
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mass-based approach twothree set-asides of allowances: one(1)

for a Clean Energy Incentive Program; (2) to support renewable 

energy projects; and the other(3) to allocate allowances based 

on an updating measurement of affected-EGU generation. The EPA 

is also proposing that a jurisdiction may choose to replace the 

federal-plan allocation provisions with its own allowancedistribution provisions. The mass-based approach is explained in 

greater detail in Section V of the Preamble.

3. Other Proposed Actions 

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

necessary or appropriate to regulate affected EGUs in certain 

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

section [&&& VI.D]. 

In today’sthis action, the EPA is also proposing a number 

of changes to the framework 111(d) regulations of Subpart B 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 

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

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

calls for plan revisions similar to the "SIP-call" provisions of 
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Section 110(k)(5); (4) an error correction mechanism similar to 

section 110(k)(6); (5) completeness criteria and a process for 

determining completeness of state plans and submittals similar 

to 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 the 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 

section 111(d) rules. The EPA intends to finalize these changes 

earlier than the finalization of the model trading rules.

C. Who Does the Proposed Action Apply to?

Regulated Entities. Existing fossil fuel-fired electric 

generating units (affected EGUs) covered by the final Clean 

Power Plan Emission GuidelinesEGs that are located in a state 

that does not have an EPA-approved state plan are potentially 

subject to this proposed action. Existing fossil fuel-fired EGUs

are those that were in operation or had commenced construction 

on or before January 8, 20144. The following NAICS codes could 

 

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, 

and that in all other respects would meet the applicability 

criteria for coverage under the GHG standards for new fossil fuelfired EGUs. 
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apply as shown in Table 1 below: 

Table 1. Examples of Potentially Regulated Entitiesa

Category

NAICS 

Code

Examples of potentially 

regulated entities

Industry 221112a Fossil fuel electric power 

generating units

State/Local 

Government

221112b Fossil fuel electric power 

generating units owned by 

municipalities

a Includes NAICS categories for source categories that own and operate 

electric power generating units (includes boilers and stationary 

combined cycle combustion turbines). 

b State or local government-owned and operated establishments are 

classified according to the activity in which they are engaged.

This table is not intended to be exhaustive, but rather 

provides a general guide for identifying entities likely to be 

affected by the proposed action. Whether an affected EGU is

affected by this action is described in the applicability 

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

subpart MMM being proposed todayUUUU. Questions regarding the 

applicability of this action to a particular entity should be 

directed to the person listed in the preceding FOR FURTHER 

INFORMATION CONTACT section.

1. What is an Affected Electric Utility Generating Unit?

For the federal plan, the definition of an affected 

electric generating unit (EGU) is identical to the definition in 
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the final Clean Power Plan Emission Guidelines (EGs)..

Additionally, the applicability of the federal plan is 

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

federal plan is any steam generating unit, IGCC,integrated 

gasification combined cycle unit (IGCC), or stationary 

combustion turbine that was in operation or had commenced 

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

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

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

a steam generating unit 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 stationary combustion turbine, 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 

 

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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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 EPAapproved state plans are not subject to the federal plan. If the 

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

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

become subject to the state plan as of the effective date 

specified in thea Federal Register notice announcingregarding

the EPA’s approval of the state plan. The EPA is not expecting 

state plans to be submitted by the states that submit negative 

 

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

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

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

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

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

in certain states or territories where the EGs did not finalize 

emission performance rates. 
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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 statestates with model trading rule options 

to consider as they prepare their state plans, the EPA is 

proposing this rulemaking concurrently with the Administrator’s 

signing and promulgation of the final Clean Power Plan EGs. 40 

CFR part 62 is updated only once per year. Thus, if 40 CFR part 

62 does not indicate that your state has an approved and 

effective plan after the compliance date has passed requiring 

state plan submittal, you should contact your state 

environmental agency’s Air Director or your EPA Regional Office 

(see Table &&&XXX in section II.D of this preamble) to determine 

if approval occurred since publication of the most recent 

version of 40 CFR part 62.

 

7 Presidential Memorandum—Power Sector Carbon Pollution Standards, 

June 25, 2013. www.whitehouse.gov/the-press-office/2013/06/25/ 

presidential-memorandum-power-sector-carbonpollution-standards.
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D. What Should I Consider as I Prepare my Comments?

Submitting CBI

Do not submit information that you consider to be CBI 

electronically through www.regulations.gov or email. Send or 

deliver information identified as CBI to only the following 

address: 

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

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

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

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

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

addition to one complete version of the comment that includes 

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

contain the information claimed as CBI must be submitted for 

inclusion in the public docket. Information marked as CBI will 

not be disclosed except in accordance with procedures set forth 

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 
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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 WWW through the Technology Transfer Network (TTN) web 

site. Following signature, the EPA will post a copy of the 

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

provides information and technology exchange in various areas of 

air pollution control. Additional information is also available 

at the same web site.

II. Background Information

A. What is the Regulatory Development Background for this

Proposed Rule?

On &&&July 31August 3, 2015, the EPA finalized the Clean 

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

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

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

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

construction before January 8, 2014. States with existing EGUs 

subject to the guidelines are required to submit to the EPA by 

August 31, 2016, a state plan that implements the emission 

guidelines.EGs. States may also make initial plan submittals in 

lieu of a complete state plan, in which case extensions can be 
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granted (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 60.27 require the EPA to develop, implement, and 

enforce a federal plan for existing EGUs located in that state. 

In addition, 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 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 

 

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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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.

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.
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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 August 31, 2016 that are at least as protective as the EGs.10

States without any existing EGUs are directed to submit to the 

Administrator a letter of negative declaration certifying that 

there are no affected EGUs in the state. No plan is required for 

states that do not have any affected EGUs. Affected EGUs located 

in states that mistakenly submit a letter of negative 

declaration will become subject to the federal plan until a 

state plan covering those EGUs becomes approved. The EPA intends 

to finalize the federal plan only for those states that the EPA 

finds failed to submit plans or whose plans the EPA disapproves.

For more information on the timing and mechanics of EPA action 

on state plans and finalization of this federal plan, see 

section II.D.1 below.

 

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

complete initial section 111(d) submission.
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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 

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

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

a state plan submission must be accompanied by other materials 

in addition to the regulatory provisions. These requirements are 

set forth in the final CPP EGs and framework regulations of 40 

CFR Part 60, subpart B. For instance, they include a formal 

letter of submittal from the Governor or his or her designee, 

evidence that the rule has been adopted into state law and that 

the state has necessary legal authority to implement and enforce 

the rule, and evidence that procedural requirements, including 

public noticeparticipation under 40 CFR 60.23, have been met. 
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In further support of state use of the model rules, we are 

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

incorporated by reference with a minimum of changes that 

arewould be necessary to make the rule appropriate for use by 

states. This way, a state may incorporate by reference the model 

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

plan with few if any adjustments. States may make changes to the 

model trading rule, so long as they still meet the requirements 

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

trading rule – for instance,such as by expanding the scope of 

eligibility of projects that may generate ERCs in a rate-based 

trading program –, the EPA may still approve the plan, but the 

EPA would conduct appropriate review of such provisions for 

consistency with the EGs and the state would needhave to be 

conducted.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 
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federal plan as such. 

Recognizing the amount of time The EPA’s approval of a 

state plan, including a plan that adopts the model trading rule, 

will be the result of an independent notice-and-comment 

rulemaking process. Without prejudging the outcome of that 

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

able to go through their decision making processes, the EPA 

intends toapprove or “conditionally approve” state plans that 

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

states an immediate additional pathway to an ultimately 

approvable state plan. The condition for approval of a state 

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

commit to adoptare substantially similar, but not identical to,

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

materials explaining why any changes to the final rule are not 

being adopted, and demonstrating that rules. Ultimately, state 

plans must meet the requirements of the EGs for approvability. 

Thus, a conditional approval would be based on a condition that 

the state plan based on the proposed model trading rule 

continuestake such actions as may be necessary by a date certain

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

explicitly provide for conditional approvals in the section 

111(d) framework regulations. See &&&Section VII.B.)
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In accordance with the EGs, the process for review and 

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

model trading rules or otherwise, would occur once the states 

have made their submissions by August 31, 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 two years before submitting a full state plan 

for EPA approval. The EPA believes it could be beneficial for 

coordination purposes if a state that is interested in adopting 

one of the model trading rules and intends to make an initial 

submittal rather than submit a full plan next August were to

indicate this, and which one, in their submittal. This is not an 

additional requirement beyond what the EGs require for initial 

submittals, however.

The EPA strongly encourages states to consider adopting one 

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

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

by states would help to ensure consistency between and among the 

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

broad trading program that spans multi-state regions or operates

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

operate less as individual, isolated entities and more as 

multiple components of a large interconnected system designed to 
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integrate a range of functions that ensure an uninterrupted 

supply of affordable and reliable electricity – and, for the 

past several decades, 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 it

performs. In addition, consistency of requirements benefits the 

affected EGUs, as well as the states and the EPA as 

administrators and implementers of a trading program. States of 

course remain free to develop a plan of their own choosing to 

submit to the EPA for approval following the criteria set out in 

the final Clean Power Plan EGs. 

The EPA believes there are compelling policy reasons that 

support the provision of a proposed model trading rule at this 

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

comments submitted on the proposed EGs that there is a strong 

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

the deadline for state submittals under the EGs. According to 

these stakeholders, model rules can provide predictability for 

planning purposes, both among states and affected EGUs. In 
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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, which, again, also serves as the proposed 

federal plan, addresses these policy interests.

The approach of proposing model trading rules that are 

identical in all key respects to proposed federal plans that may 

be promulgated later, is consistent with prior section 111(d) 

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

the Clean Air Interstate Rule (CAIR) model rule in Part 96 (70 

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

with the federal CAIR in Part 97 (71 FR 25396; April 28, 2006).11

While these identical programs for model rules and FIPs were 

finalized in separate parts of the Code of Federal Regulations, 

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 

 

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

rules, the content of EGs and their corresponding federal plans 

have had significant overlap.
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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 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 3. 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, 

Pennsylvania, 

West Virginia

Region IV Florida, Georgia, 

North Carolina, 

Alabama, 

 

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

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 

Mariana Islands

Region X &&& &&& Alaska, Idaho, 

Oregon, 

Washington
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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 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 EG, state plans 

will be due on [August 31, 2016]. States are also allowed to 

seek a two year extension for a final plan submittal, upon 

submitting a satisfactory initial submittal by the same 

deadline. See 40 CFR 60.5755, 60.5760(b). If a state fails 

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

 

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 
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if either a final state plan or an initial submittal, does not 

meet the requirements of the EG, the agency will take the 

appropriate steps to finalize and implement a federal plan to 

that state’s EGUs. 

Further, states will remain free, and indeed are strongly 

encouraged, to submit an approvable state plan even after 

promulgation of the federal plan for their jurisdictions. Upon 

approval of the state plan by the EPA, the federal plan will no 

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

&&&40 CFR 60.5720.

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

Plan, and other Proposed Actions

Today’sThis action co-proposes two approaches to the 

federal plan, both of which also constitute proposed model 

trading rules that states could adopt as state plans for EPA 

approval. The EPA currently intends to finalize one or both of 

 

“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 section 111(d). Rather, the EPA steps into 

the shoes of the state to carry out the 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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the model trading rules by next summer so that they may be 

available to states as soon as possible to help inform their 

state plan development efforts prior to the initial submittal 

deadline of August 31, 2016.14 If the EPA finalizes the model 

trading rules in that timeframe, the only direct consequence 

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

particular approaches to the design of their state plan that the 

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

trading rule will not constitute a final action with respect to 

a federal plan for the affected EGUs in any state. Rather, the 

proposed federal plan will remain just that, a proposal. The EPA 

will promulgate a final federal plan for any state only after it 

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

fully or partially disapproved a submitted state plan. The EPA 

will go through a public notice and comment process before 

disapproving a submitted and complete state plan, in whole or 

part. The EPA invites comments on this staged approach to 

finalizing one or more model trading rules on the one hand 

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

 

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

either in the new subpart or subparts of the Part 62 of Title 40 

of the Code of Federal Regulations (CFR) as proposed, or in a final 

document that is not published in the CFR.
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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 section 111(d). For more 

detailed discussion of these changes, see &&&Section VII of this

Preamble.. This aspect of today’sthis proposal is separate from 

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

finalize these changes on a timeline earlier than both a model 

trading rule and the federal plan. 

Under the framework regulations and the final EGs, at 40 

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

initial timelines for EPA action on state submittals and, 

potentially, the promulgation of a federal plan will be as 

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

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

The EPA will have twelve 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 six months from the date of a 

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

meet completeness criteria and constitutes a failure to submit a 

plan. In the case of initial submittals under 60.5760,5765, the
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EPA will have 60 days from August 31, 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 twelve months

from the date of a state's initial submittal to promulgate a 

federal plan forfrom the affected EGUs in statesdate of its 

finding that a state failed to submit a complete and approvable 

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

state failed to submit a state plan.)

The timeframes stated in the previous paragraph reflect the 

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

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

federal plan for a state immediately upon making a finding of 

failure to submit a complete state plan or initial submittal, or 

upon making a finding of final disapproval of a state plan.

Congress gave the EPA authority in section 111(d)(2), as it did 

in section 110(c), to promulgate a federal plan at any time 

after it disapproves or finds a failure to submit a state plan. 

The Supreme Court has recognized that under this authority, the 

EPA may promulgate a Federal Implementation PlanFIP “at any 

time” within the two-year limit of 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 . . . 
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.” Id. Where, as here,., It is essential to implement plans for 

the control of emissions of carbon dioxide expeditiously, and 

avoid unnecessary delay. Among other reasons, this will provide 

affected EGUs regulatory certainty, and avoid any unnecessary 

delay and will assist the regulated entities as well as those 

authorities with responsibility for ensuring grid reliability to 

have as much time as possible to plan for the 2022 compliance 

start date set in the EGs. Thus, it is reasonable to propose 

this federal plan now so that federal plans will be ready to be 

promulgated quickly in cases where states have failed to submit 

a plan or their plans are found unsatisfactory. In addition, 

this will assist the regulated entities as well as those 

authorities with responsibility for ensuring grid reliability to 

have as much time as possible to plan for the 2022 compliance 

start date set in the EGs.

It is the agency’s intention to promulgate federal plans 

promptly for states who do not submit plans or initial 

submittals by August 31 of next year. However, the effect of 

putting the federal plan in place at that time would ultimately 

be limited in impact upon states. Because the EPA would 

implement the federal plan, its promulgation does not obligate 

state officials to take any actions themselves. Further, States 

remain free - and EPA in fact encourages States - to submit 
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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 notice, the EPA is proposing regulatory text 

setting out the substantive provisions for both of the proposed 

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

specific regulatory text that would, if finalized, actually 

promulgate a federal plan for each state for which this proposed 

federal plan might be applied.15 We currently envision that this 

language would be in the form of a new section to the statespecific subparts of Part 62 and would be ministerial in nature. 

It would likely provide that the affected EGUs in each such 

 

15 The minimum contents of a notice of proposed rulemaking under 

the CAA are set forth at CAA section 307(d)(3) and 5 U.S.C. 553(b). 
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state are subject to a federal plan and would then crossreference or incorporate by reference the substantive provisions 

of one of the final model trading rules,two subparts proposed 

today (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 (Aug.; August 8, 2011).

E. Use of the Model Trading Rule as a Backstop

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

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

rule could function well as the federally enforceable “backstop” 

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

state plans.16 (The proposed federal plan does not itself require 

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

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

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

 

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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federally enforceable backstop in a state measures approach are 

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

and &&&VIII.C.4.c.2. 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 

emission guidelinesEGs, and identify all necessary state 

administrative and technical procedures for implementing the 

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

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

backstop emission standards must make up for any shortfall in CO2

emission performance during a prior plan performance period that 

led to triggering of the backstop.

The EGs explicitly recognized that the backstop emission 

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

the EPA is proposing in this action. As discussed in Section 
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&&&II.B 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 

enforceable backstop in a state measures plan, this does not 

mean that the backstop is itself the federal plan. Rather, the 
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model rule becomes adopted as a part of the state plan. Both 

approaches to the model trading rule are “emission standard” 

approaches under the EGs, in which an emissions standard in the 

form of an allowable rate of emissions, or an allowance system, 

is imposed and federally enforceable on the affected EGUs. The 

EPA may also handle the administration of the trading program 

for states utilizing the model trading rule. However, even 

though the backstop may take the form of an EPA-administered, 

federally-enforceable trading rule, this does not mean that a 

federal plan has been put into effect. The state retains all of 

its rights and responsibilities with respect to the 

implementation and enforcement of the backstop as a component of 

its state plan.

1. Applicability and Enforceability

If promulgated for the affected EGUs in a particular state, 

this federal plan will require affected EGUs to meet specific 

emission standards for CO2 and related requirements. These

enforceable compliance obligations will apply to the owners and 

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

obligation falls on states or state officials (except to the 

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

 

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

and similar to a FIP or an approved SIP under CAA section 110. 

See CAA section 111(d)(2)(B), 42 U.S.C. 7411(d)(2)(B) (power to 

enforce state and federal plans).), section 113(a)–(h), 42 

U.S.C. 7413(a)-(h), and section 304, 42 U.S.C. 7604. This means 

that the Administrator and the state havehas the ability to 

enforce against violations and secure appropriate corrective 

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

other third parties maintain the ability to enforce against 

violations and secure appropriate corrective actions pursuant to 

CAA section 304.

 

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 

notice. These changes are discussed in Section &&&VII 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 sourcesaffected EGUs in states 

covered by the proposed federal plans and sourcesaffected EGUs

in states covered by state plans under the following conditions, 

which are discussed further below the list:

• The state plan must be approved.

• The state plan must implement the same type of trading 

program as the federal plan trading program in order to be 

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

programs couldcan link to mass-based trading programs only,

and rate-based trading programs couldcan link to rate-based 

trading programs only.

• The state plan must use the identical compliance instrument 

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

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

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

(we are also requesting comment on expanding this to 

include a state plan that uses an EPA-designated tracking 

system that is interoperable with an EPA-administered 

system, as detailed below).
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The EPA proposes that interstate ERC trading could occur 

both i)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, and ii)2) from sourcesaffected EGUs in such stateplan-covered states to sourcesaffected EGUs in federal-plancovered 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 EPA-designated ERC 

tracking system that is interoperable with an EPA-administered 

ERC tracking system. The EPA also takes comment on allowing a 

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

the proposed conditions for linkages and that uses an EPAdesignated ERC tracking system to register with the EPA, and 

after registration, to link with states covered by the ratebased trading federal plan. There are multiple benefits to a 

registration requirement, which include ensuring that the 

tracking systems are functionally interoperable.

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

interstate allowance trading could occur in both directions, 

i.e., from affected EGUs in states covered by the mass-based 
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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, thus a condition of 

linkage to the federal plan is that a state plan must issue its 

allowances in short tons. The agency also requests comment on 

whether to extend linkage to state plans that issue allowances 

in metric tons and on what provisions would be necessary to 

implement such linkages. The EPA believes that considerations 

for linkages to state plans that use metric tons may include 

tracking system design, and stipulation of which parties convert 

allowance values and at what stage of compliance operations the 

conversion occurs. The agency requests comment on these and any 

other considerations for linkages between the federal plan and 

state plans that issue allowances in metric tons.18

The EPA also requests comment on expanding the scope of 

interstate trading to include linking states covered by the 

 

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

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

approved mass-based trading state plan meeting the proposed 

conditions for linkages and that uses an EPA-designated

allowance tracking systemssystem that is interoperable with an 

EPA-administered allowance tracking system. The EPA also 

requests comment on a registration requirement for linking to an 

EPA-designated tracking system, as noted above for the ratebased approach.

In the Clean Power Plan EGs, the EPA promulgated 

requirements that apply to an emissions budget trading state 

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

the opportunity for such a state plan to be potentially 

approvable for linking to other state plans. Those requirements 

include accounting adjustments for net import and export of 

allowances [&&& cite to final(Clean Power Plan EGs preamble 

section]. VIII). In this proposed rule, the proposed approach to 

link from the mass-based trading federal plan to state plans 

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

include non-affected emission sources. The EPA requests comment 

on this proposed approach.

The EPA believes that a broad trading region provides 

greater opporunitiesopportunities for cost-effective 

implementation of reductions compared to trading limited to a 
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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, for the rate-based and mass-based approaches, 

respectively.

2. Interstate Effects and Addressing Potential Leakage

The final Emission GuidelinesEGs recognized that emission 

reduction measures will likely have impacts beyond their 
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bordersacross states and across categories of generation because 

of the interstate naturedynamic flow of power on the regional 

grid (see final emission guidelinesEGs Sec. VIII.L for a 

detailed discussion of interstate effects and addressing 

potential leakage). Interstate effects and leakage could

interfere with meeting reduction obligations under federal and 

state plans, usually because of dynamics resulting from the 

regional grid existing in combination with differences in statebased characteristics, including the portfolio of affected EGUs

within a particular state, the availability of eligible state 

measures, existing policies in the state and the cost of 

compliance in the state.). In the final GuidelinesEGs, the EPA 

acknowledged that some amount of interstate movement of 

generation will inevitably be present and unavoidable and may 

affect how affected EGUs achieve the applicable CO2 emission 

performance rates or state goals under a state plan. In fact, 

the final guidelines are premised in part on reductions due to 

the movement of generation from higher-emitting to loweremitting affected EGUs. However, the risk of foregone emission 

reductions due to the moveement of generation should be 

minimized. The final guidelines also discussed how the use of 

the sub-categorized uniform emission rates for steam and gas,

and the state plan requirements (particularly their approach to 
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accounting for measures that cross state boundaries), serve to 

reduce the risk of interstate effects.movement of generation 

should be minimized. 

The final guidelinesThe final specify the concern of 

leakage, which is defined in Sec. VII.D 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 created differing

incentives to run for affected existing EGUs and for new 

sources, which could result 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 subcategories CO2 performance rates and rate-based goals. 

Sec. VII.D of the final EGs details the requirement for 

addressing leakage and why it is needed, and Sec. VIII.J 
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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 allocation approaches 

to address leakage, specifically through establishing an outputbased allocation set-aside and a set-aside that encourages the 

installation of RE. These proposed strategies are detailed in 

Sec. V.D of this proposal.

There are other various ways that the final EGs and the 

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

foregone reductions, including through the particular structure 

of the subcategorized CO2 performance rates, state goals and 

compliance accounting, that deemphasize the differences between 

states. Additionally, there are restrictions to avoid forgone 

emissions, including the condition that jurisdictions under the 

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

rate-based federal plan jurisdictions, must used the 

subcategorized CO2 performance rates. This eliminates differing 

incentives between states in rate-based ERC issuance and 

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

EGs, the EPA also discussed the concern that CO2 emissions 

reductions would be eroded in situations where an affected EGU

in a rate-based state counts the MWh from measures located in a 
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mass-based state, but the generation from that measure acts 

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

expected CO2 emission reduction actions in the rate-based state 

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

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

requires thatrestricts ERC issuance for any emission reduction 

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

measures located in a state with a mass-based state plan can 

only be approved for ERC issuance for use by a state under a 

rate-based federal plan if it can be demonstrated that that 

load-serving entities in the electricity generated is delivered 

withrate-based state have contracted for the intentiondelivery 

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

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

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

the provision of a power delivery contract or power purchase 

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

for the supply of the MWhs in question and 2)providing

documentation that the electricity was treated as comparable to 

a generation resource used to serve regional load that included 

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

part of the project application for ERC issuance to the EPA or 
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its agent from the RE provider in the mass-based state. Once the 

project is approved, subsequent applications for issuance of 

credit to the EPA will need to reference that the MWh submitted 

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

state. The EPA requests comment on this approach.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 issuedERCs in 

a rate-based state.

Under the proposed mass-based approach there is a restriction 

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

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

for their generation are barred from having ERCs issued for that 

generation in a rate-based state.

Under the proposed mass-based approach, double counting due 

to interstate effects is minimized because compliance with mass 

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

face the problem of generation shifting to unaffected sources, 

particularly new generation, if the plan does not include new 
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generation under a cap) that operate within the state but outside 

of the mass cap. This is much less of a concern under rate-based 

plan, and thus could mean that mass-based goals and CO2 performance 

rates (along with associated rate-based goals) may not be 

equivalent if leakage is not addressed. Therefore, the final 

emission guidelines require that mass-based plans make a 

demonstration that leakage to new unaffected EGUs has been 

sufficiently addressed. To meet this requirement in the mass-based 

federal plan, the EPA is proposing allocation options that mitigate 

leakage to new unaffected EGUs. Specifically, the EPA is proposing 

to implement output-based allocation, which reserves some 

allowances to be allocated to affected EGUs based, in part, on 

their level of electricity generation in a recent period(s). 

Therefore, the allocations are not fixed, but instead update over 

time depending on an affected EGU’s generation. Affected EGUs can 

increase their allowance allocation based on their generation, 

which incentivizes generation to remain under the mass, thereby 

helping to avoid leakage of generation to unaffected EGUs. 

Additionally, a set-aside awarding allowances for RE generation is 

being proposed, which can make more RE available in states with a 

mass-based federal plan, and increase the amount of low-emitting 

generation available in the states. The need to address leakage 

and both of the proposed set-asides are discussed in detail in 
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Sec. &&&V.D.3. The EPA takes comment on both the set-aside for 

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

generation.

The EPA requests comment on the treatment 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. 

Applicability and Inventory of Affected Units

[&&&under developments]

3. Provisions to Encourage Early Action

&&&Placeholder while this section being worked on 

offline&&&

B. Inventory of Emissions

Fossil fuel-fired electric utility generating units (EGUs) 

are by far the largest emitters of GHGs among stationary sources 

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

This section describes the amounts of these emissions and places 

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

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

 

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

2013”, Report EPA 430-R-15-004, United States Environmental 
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The EPA implements a separate program under 40 CFR Part 98 

called the Greenhouse Gas Reporting Program20 (GHGRP) that requires 

emitting facilities over threshold amounts of GHGs to report their 

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

section also places emissions from fossil fuel-fired EGUs in the 

context of the total emissions reported to the GHGRP from 

facilities in the other largest-emitting industries. 

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

with commitments under the United Nations Framework Convention on 

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

trends, is organized by industrial sectors. It provides the 

information in Table 2 below, which presents total U.S. 

anthropogenic emissions and sinks21 of GHGs, including CO2

emissions, for the years 1990, 2005 and 2013.

Table 2. U.S. GHG Emissions and Sinks by Sector (million metric 

tons carbon dioxide equivalent (MMT CO2 Eq.))22

 

Protection Agency, April 15, 2015.

www.epa.gov/climatechange/ghgemissions/usinventoryreport.html

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

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

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

forests or underground or deep sea reservoirs of 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.
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SECTOR 1990 2005 2013

Energy23

 

5,290.5

 

6,273.6

 

5,636.6

Industrial Processes 

and Product Use 342.1 367.4 359.1

Agriculture 448.7 494.5 515.7

Land Use, Land-Use 

Change and Forestry

 

13.8 25.5 23.3 

Waste 206.0 189.2 138.3

Total Emissions 6,301.1 7,350.2

 

6,673.0

Land Use, Land-Use 

Change and Forestry 

(Sinks)

 

(775.8) (911.9) (881.7)

Net Emissions (Sources 

and Sinks)

 

5,525.2 6,438.3

 

5,791.2

Total fossil energy-related CO2 emissions (including both 

stationary and mobile sources) are the largest contributor to total 

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

 

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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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 3 below presents total 

CO2 emissions from fossil fuel-fired EGUs, for years 1990, 2005 

and 2013.

Table 3. 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.

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.

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.

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 22.4
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[&&& under development]

Compliance Schedule

In accordance with the schedule set out in the Emission 

Guidelines, the federal plan is proposed to be implemented in a 

phased approach. The first period, corresponding to the interim 

period in the EG, is proposed to run from beginning of calendar 

year 2022 until end of calendar year 2029 (January 1, 2022 to 

December 31, 2029). The final period would run from beginning of 

calendar year 2030 (January 1, 2030) indefinitely into the 

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

EPA action amending the EGs. The first period is proposed to be 

comprised of three “compliance periods,” set by calendar year. 

The first compliance period will be from January 1, 2022 to

midnight, December 31, 2024 (three calendar years). The second 

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

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

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

2029 (two calendar years).

Under the Emission Guidelines, midnight, December 31, 2029 

marks the end of the interim period, and the beginning of the 

final period. The EPA proposes that the compliance periods in 

the final period will each be two calendar years. Thus, the 

97.5 97.9 
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first compliance period after 2030 would be from January 1, 2030 

to midnight, December 31, 2031. The second compliance period 

would be from January 1, 2032 to midnight, December 31, 2033. 

This would repeat accordingly unless changed by EPA through a 

revision to the federal plan or other action.27

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, 

 

27 This schedule would be the same under either a rate- or mass-based approach. 
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the agency intends to establish the infrastructure for operating 

a federal trading program and to work closely with affected EGUs 

in the states where the federal plan is promulgated prior to the 

compliance period in 2022. 

The EPA requests comment on whether there is any reason to

use shorter compliance periods than the proposed periods, and how 

modifying these periods could be done in a manner that is 

consistent with the Emission Guidelines. To the extent this 

schedule is governed by the schedule set in the final EG, the 

agency is not re-opening such issues, and comments regarding the 

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

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

present comprehensive total U.S. greenhouse gas emissions and 

comply with commitments under the UNFCCC, the EPA collects detailed 

GHG emissions data from the largest emitting facilities in the 

U.S. through its Greenhouse Gas Reporting Program (GHGRP). Data 

collected by the GHGRP from large stationary sources in the 

industrial sector show that the utility power sector emits far 

greater CO2 emissions than any other industrial sector. Table 4 

below presents total GHG emissions in 2013 for the largest emitting 

industrial sectors as reported to the GHGRP. As shown in Table 3 

and Table 4, respectively, CO2 emissions from fossil fuel-fired 
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EGUs are nearly three times as large as the total reported GHG 

emissions from the next ten largest emitting industrial sectors in 

the GHGRP database combined.

Table 4. Direct GHG Emissions Reported to GHGRP by Largest Emitting 

Industrial Sectors (MMT CO2e)28

C. Affected EGUs

For the CPP EGs 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, 2014,29 and that meets the following criteria, 

 

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

18, 2014. www.ghgdata.epa.gov/ghgp/main.do.

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

sources is based on the date that the EPA proposes action on such 

sources. January 8, 2014 is the date the proposed GHG standards of 

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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which differ depending on the type of unit. To be an affected 

EGU, such a unit, if it is a steam generating unit or IGCC, must 

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

utility power distribution system and have a base load rating 

greater than 260 GJ/h (250 MMBtu/h) heat input of fossil fuel 

(either alone or in combination with any other fuel). If such a 

unit is a stationary combustion turbine, 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 stationary combustion turbine 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) 

 

performance for new fossil fuel-fired EGUs were published in the 

Federal Register (79 FR 1430).
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combustion turbine means any stationary combustion turbine which 

recovers heat from the combustion turbine engine exhaust gases 

to heat water or another medium, generate steam for useful 

purposes other than exclusively for additional electric 

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

useful purpose.

We note that certain affected EGUs are exempt from 

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

that may be excluded under the Emission GuidelinesEGs are those 

that (1) are subject to subpart TTTT as a result of commencing 

modification or reconstruction; (2) steam generating units or 

IGCC units that are currently and always have been subject to a 

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

less on an annual basis; (3) 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) 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 
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enforceable permit limiting, or have historically limited, 

annual net electric sales to a utility power distribution system 

to the product of the design efficiency and the potential 

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

(6) serve a generator along with other steam generating 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 Part 60; 

or (8) are a commercial or industrial solid waste incineration 

unit that is subject to subpart CCCC of Part 60.30

The applicability of this proposed federal plan follows the 

same applicability criteria as the final Emission GuidelinesEGs. 

 

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

existing source fossil fuel-fired EGUs that met the applicability 

criteria for coverage under the final GHG standards for new fossil 

fuel-fired EGUs being promulgated under 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 

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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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 CPP. In this TSD, 

each affected EGU is assigned its proposed applicable standards 

if a federal plan is applicablewere to be promulgated for that 

affected EGU at any time. The EPA requests comments and updates 

to this list of affected units. Section VI.C of the CPP 

describes the data used in setting the standards and how an 

inventory of affected units has been compiled.

D. Compliance Schedule

In accordance with the schedule set out in the EGs, the 

federal plan is proposed to be implemented in a phased approach. 

The first period, corresponding to the interim period in the EG, 

is proposed to run from beginning of calendar year 2022 until 

end of calendar year 2029 (January 1, 2022 to December 31, 

2029). The final period would run from beginning of calendar 

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 (three 
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calendar years). The second compliance period will be from 

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

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

to midnight, December 31, 2029 (two calendar years).

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 two calendar years. Thus, the first compliance 

period after 2030 would be from January 1, 2030 to midnight, 

December 31, 2031. The second compliance period would be from 

January 1, 2032 to midnight, December 31, 2033. This would 

repeat accordingly unless changed by the EPA through a revision 

to the federal plan or other action.31

The EPA recognizes that the compliance periods provided for 

in this rulemaking are longer than those historically and 

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

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 

 

31 This schedule would be the same under either a rate- or massbased approach. 
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Limiting Potential to Emit through SIP and §112 Rules and 

General Permits. The EPA determined that the longer compliance 

periods provided for in this rulemaking are acceptable in the 

context of this specific rulemaking because of the unique 

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

performance standards related to those long-term impacts.

Prior to the beginning of the first compliance period in 

2022, the agency intends to establish the infrastructure for 

operating a federal trading program and to work closely with 

affected EGUs in the states where the federal plan is 

promulgated prior to the start of the first compliance period in 

2022. We request comment on whether it would be possible to 

grant, on a case-by-case basis, 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.

D.E. Addressing Reliability Concerns

The proposed federal plan washas been designed to ensure 

that, to the greatest extent possible, implementation would not 

interfere with the power sector’s ability to maintain electric 

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

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 
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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 

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 

 

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

An Overview of the Technology, the Marketplace, and Government 

Regulations, IEEE Press, at 160 (2010).

33 Id.
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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 six years before reductions are 

required and an eight-year period from 2022 to 2029 to meet 

interim goals. This allows time for planning and steady,

measured implementation.

Second, the federal plan is a market-based trading program 

which will allow affected EGUs the opportunity to buy and sell 

emissions credits or allowances as well as bank them. The EPA’s 

proposed federal plan includes two alternative approaches; a 

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

Trading programs of both types have many positive attributes.

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

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

maintain the reliability of the nation’s electricity supply. 

Such a program does not restrict unit-level operational 

 

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

Planning, available at 

www.nerc.net/standardsreports/standardssummary.aspx.
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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 

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 
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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 

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.
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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 

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. 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-
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aside allowances; the size of the set-aside; and the timing of 

distribution of allowances from the reliability set-aside. 

Additionally, the EPA requests comment on how a reliability “setaside” 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 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 and 

allowances to support reliable electricity generation and 

transmission to be utilized in the event of this kind of 

reliability emergency.

E.F. Worker Certification

In the EGEGs, the EPA suggested that to ensure that 

emission reductions are realized, it is important that 

construction, operations and other skilled work undertaken 
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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.

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

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

standard of performance under a plan prescribed under this 

paragraph, the Administrator shall take into consideration, 

among other factors, remaining useful lives of the sources in 

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

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

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

Emission GuidelinesEGs, we explained how the Guidelines permit 

states in applying a standard of performance in their state 

plans to consider the remaining useful life of a facility. We 
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determined that it was appropriate to specify that the general 

variance provisions in 40 CFR 60.24(f) should not apply to the 

class of affected facilities covered by these Guidelines. 

&&&citation. We concluded that facility-specific factors and in 

particular, remaining useful life, do not justify a state making 

further adjustments to the performance rates or aggregate 

emission goal that the Guidelines define for affected EGUs in a 

state and that must be achieved by the state plan. 

Because the Guidelines do not allow for states to deviate 

from state-wide targets goals based on remaining useful life, 

the EPA does not believe such goal adjustments are necessary or 

appropriate in the federal plan either. Nonetheless, this does 

not obviate the requirement that the EPA itself, in the design 

of its federal plan, consider, among other factors, the 

remaining useful lives of the affected facilities. The agency 

therefore proposes anthe following analysis of this factor in 

&&§ion III.G.1..35

 

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 

section 111(d)(1), and for the same reasons, believe it is distinct 

from the factor Congress directed the agency to consider in section 
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In section III.G.2, we discuss a related concern raised by 

some stakeholders, which is whether the federal plan could 

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

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

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

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

Nonetheless, we undertook analysis of whether and to what extent 

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

demonstrates that this is not likely to be a widespread issue 

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

all other aspects of this discussion.

Consideration of Remaining Useful Lives

Congress added the “remaining useful lives” factor to 

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 

 

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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useful lives to not be required to install capital-intensive 

pollution control devices to meet emission standards that would 

only be used for a short period of time before a plant ceased 

operation. A House of Representatives report on a predecessor 

bill to the enacted statute stated, “Older plants with 

relatively short remaining useful lives might have chosen to 

cease operation if the only means of emission limitation 

available to meet emission limits were pollution control 

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

This language is probative of the fact that Congress viewed 

“remaining useful lives” as a consideration of the physical age 

offor facilities. As explained below, we believe with relatively 

little remaining useful life. We are confident the proposed 

federal plan will not force costly pollution control investments 

at older plants with short remaining useful lives.

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 
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“remaining useful liveselives” factor is considered. The statute

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

consideration mandate the agency to prevent all premature 

retirements of affected EGUs, to impose no emission requirements 

on older affected EGUs, or to ensure that profitability is 

maintained at all times for all affected EGUs. Congress knew how 

to explicitly exempt older plants from CAA requirements at the 

time of the 1977 Amendments. For example, Congress excluded 

plants in existence before August 7, 1977 from the 

preconstruction requirements of the PSD/non-attainment new 

source review 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 

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 
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consider in determining the best available retrofit technology 

(BART) for a particular source. Consistent with congressional 

purpose, the EPA has implemented this factor in the regional 

haze program for many years through the BART guidelines, in 

Appendix Y to 40 CFR Part 51. The BART Guidelines provide: 

The “remaining useful life” of a source, if it 

represents a relatively short time period, may affect the 

annualized costs of retrofit controls. ... If the remaining 

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

amortization based on the type of control], the remaining 

useful life has essentially no effect on control costs and 

on the BART determination process. Where the remaining 

useful life is less than the time period for amortizing 

ocstscosts, you should use this shorter time period in your 

cost calculation.

40 CFR Part 51, App. 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 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 in that the plan does 

not mandate that plants with short remaining useful lives must

install costly, capital-intensive pollution control upgrades.by 
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providing for trading and other flexibilities authorized in the 

EGs. To summarize, these include: relatively long periods for 

affected EGUs to come into compliance, the ability to credit 

early action, the use of emissions trading, the use of multiyear compliance periods, and the ability to link to other 

federal or state plans to create larger emissions markets. The 

federal Plan is proposed to include a Clean Energy Incentive

Program as provided for in the EGs, which will credit early 

action and ease compliance in the first years of the program. 

These tools will create economic incentives that reward overperformance of some affected EGUs, and allow others to simply 

acquire credits or allowances to comply with their emission 

standard, thereby avoiding the need for installation of costly 

pollution controls at sources with a short remaining life.

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

that it adequately, and inherently, takes into account the 

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 
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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 

 

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 

less stringent standards significantly more reasonable) are not 

expected to arise, and thus, the agency proposes to make § 60.27(e) 

inapplicable in this federal plan.
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facility would need to comply for fewer compliance periods and 

would need proportionately fewer ERCs or allowances than the 

second facility. Buying ERCs or allowances as a compliance 

method could avoid excessive up-front capital expenditures that 

might be unreasonable for facilities with short remaining useful 

lives, and therefore addresses the consideration of “remaining 

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

also would reduce the potential for stranded assets.

In addition, the timing of the federal plan limits the 

immediate costs of compliance, particularly for facilities that 

have useful lives ending before 2022, but also for facilities 

that have useful lives ending before 2030. There are no 

compliance obligations for affected EGUs under this federal plan 

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

point, the agency is using a step-down approach, orfollowing the

glide path provided for in the EGs, which begins with relatively 

higher emission targets that will slowly strenghten over the 

interim performance period from 2022-2029 through three multiyear compliance periods. The final, most stringent, compliance 

obligation does not begin until 2030. 

Further, unlike state plans that can be more stringent 

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

than the Emission GuidelinesEGs, and, as explained in the EGs,
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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 collective groups of EGUs, rather than 

for an individual EGU. In considering the remaining useful lives

of facilities under a federal plan, the EPA believes this 

approach to setting the emission standards, coupled with the 

ability to trade, adequately accounts for remaining useful lives

of facilities. In essence, it allows the facilities to comply 

with the federal plan through the purchase or acquisition of 

ERCs or allowances, and to avoid the need to make costly 

investments in control technology for plants that have short 

remaining useful lives.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.

 

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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Potential for Stranded Assets

While we believe the analysis above satisfies the 

consideration of remaining useful lives in this proposed federal 

plan, the agency in its discretion has also considered a 

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

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

that the CPP will force or mandate the premature retirement of 

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

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

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

warranted with respect to the proposed federal plan. The 

analysis presented here is meant to demonstrate that, on the 

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

widespread stranded assets.

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

G.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 
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requirements independent of those that would be required under 

title V of the Clean Air Act and the regulations implementing 

title V, 40 CFR Parts 70 and 71.38 All major stationary sources 

of air pollution and certain other sources are required to apply 

for title V operating permits that include emission limitations 

and other conditions as necessary to assure compliance with 

applicable requirements of the CAA, including the requirements 

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

§§ 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 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,

 

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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will need to be addressed in the title V permits. For example, 

requirements under the proposed federal plan concerning 

designated representatives, monitoring, reporting, and 

recordkeeping, the requirement to either meet an emission rate 

(including through holding ERCs (rate-based approach),)), or to 

hold allowances covering emissions (mass-based approach))) will 

be “applicable requirements” to be addressed in the permits.

The EPA does not believe this approach is affected by the 

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

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

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

of determining whether a source is a major source required to 

obtain a title V operating permit. In accordance with that 

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

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

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

stationary source to obtain a title V permit solely because the 

source emits or has the potential to emit GHGs above the 

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

directed the EPA to consider whether any further revisions to 

its regulations are appropriate in light of UARG v. EPA, and, if 

so, to undertake to make such revisions. As the agency made 

clear in a memorandum to Regional Administrators last year, 
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“While the EPA will no longer apply or enforce the requirement 

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

has the potential to emit greenhouse 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 section 111(d) will 

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

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

related requirements for GHGs (here, carbon dioxide) on affected 

EGUs. See 40 CFR 70.2, 71.2 (definition of “applicable 

requirement” includes “any standard or other requirement under 

section 111 of the Act, including section 111(d)”) (emphasis 

added). Thus, an affected EGU may be required to modify theirits

existing title V permit, or obtain a new permit if it does not 

already have one, if it becomes subject to an emission standard 

for carbon dioxide under a section 111(d) federal plan.

 

39 Memorandum from Janet McCabe, Acting Assistant Administrator, 

Office of Air and Radiation, and Cynthia Giles, Assistant 

Administrator, to Regional Administrators, Regions 1-10, at 5 

(July 24, 2014).
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The title V permits program is structured to provide 

flexibility for market-based approaches, such as allowance 

trading programs under the federal plan, including flexibility 

to make changes under such programs without necessarily 

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

regulations provide that a permit issued under title V shall 

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

similar programs or processes” applicable to the source, a 

provision stating that no permit revision is required “for 

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

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

regulations, the proposed federal plan regulations include a 

provision stating that no permit revision shall be required for 

the allocation, holding, deduction, or transfer of allowances.

once the requirements applicable to such allocations, holdings, 

deductions, or transfers of CO2 allowances are already 

incorporated in such permit. Consistent with title V 

regulations, this provision should be included in each title V 

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

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

federal plan without a revision of the title V permit of any of 

the sources involved.

As a further example of flexibility under title V, the 
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title V regulations allow the use of the minor permit 

modification procedures for permit modifications “involving the 

use of economic incentives, marketable permits, emissions 

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

minor permit modification procedures are explicitly provided for 

in an applicable implementation plan or in applicable 

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

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

changes that may be required to an operating permit with respect 

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

the minor permit modification procedures of the title V rules. 

EPA proposes that such changes may include the initial changes 

needed to the title V permit to establish the applicability of 

the trading program to the source, specify the covered units, 

and to include other permit terms that may be needed for 

implementation, including the general approach for monitoring 

and reporting. The minor permit modification procedures maycould

also be used for any subsequent changes to permit terms that may 

be needed with respect to the trading program, although we 

expect such changes to be rareinfrequent. As noted above, once a 

trading program has been established in the permit, there may be 

transactions, such as individual trades, that will require no 

formal permit modification procedures because such trading would 
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be already addressed and allowed by the permit (“provided for in 

the permit”) and provided the changes do not conflict with any 

existing terms of the permit. If a sources wishes to make an 

operationala change that would violatego against any express 

term of the permit, the permit must be revised to allow such a 

change before the source begins operation of the change. Under 

the implementation strategy described above, the EPA believes it 

would be unlikely that any change in trading allowances would 

violate a term of a permit, but this principle is important to 

keep in mind when deciding if a minor permit modification is 

neededappropriate with respect to operating a trading program in 

the context of a title V permit.

As new applicable requirements under title V, the 

requirements for covered units under the proposed federal plan 

will need to be incorporated into covered sources’ existing 

title V permits either pursuant to the provisions for reopening 

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

renewal provisions (40 CFR 70.7(c) and 71.7(c).The EPA believes 

that the approach to permitting requirements we are proposing 

here, which imposes no additional permitting requirements 

independent of title V and provides for the use of minor permit 

modification procedures, will streamline the process for sources 

already required to be permitted under title V and onfor
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permitting authorities. If there are any sources that would 

become newly subject to title V as a result of the requirements 

of this proposed federal plan, the initial title V permit that 

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

address the federal plan requirements, when finalized.

The EPA notes that the approach to title V permitting that 

it is proposing todaybeing proposed is verysomewhat similar to 

the approach adopted in the final Cross-State Air Pollution Rule 

(CSAPR). See 76 FR 48299-30 (Aug. 8, 2011). The agency recently 

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 

 

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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V permits via minor modification procedures or if only a 

specified subset of such requirements should be eligible for 

such procedures.

The EPA also notes that the applicable requirements of this 

proposed federal plan would apply to a source and are 

independently enforceable regardless of whether they have yet 

been included in the source’s Title V permit.

2. Implications for New Source Review Program

The new source review (NSR) program is a preconstruction 

permitting program that requires major stationary sources of air 

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

increase in the unit’s annual emissions. If the emissions 

increase associated with the unit’s changes exceeds the 

thresholds in the NSR regulations for one or more regulated NSR 

pollutants, including the netting analysis, the changes would 

trigger NSR. We noted that while there may be instances in which 

an NSR permit would be required, we expect those situations to 

be few.

The EPA believes the analysis of NSR applicability is 

basically the same for sources under a 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 ratebased or mass-based approach, to undertake a physical or 

operational change to improve an affected EGU’s efficiency that 

results in an increase in annuala significant net emissions 

increase of a regulated NSR pollutant. This would trigger NSR. 

However, as with state plans, the EPA believes that these 

situations will be few.

After the proposal for the Clean Power Plan was published 

in June of 2014, the United 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 
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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 

increases its operations due to generation shift from a steam 

generating unit), cannot trigger NSR.

The EPA invites comment on what actions sources might take 

to comply with the federal plan that could trigger NSR, and what 

flexibilities may be available in the existing NSR program to 

avoid the need for pre-construction review in those 

circumstances. The EPA is not proposing any changes to the NSR 

program in this action, and the agency is not reopening or 

reconsidering any prior actions or determinations related to NSR 

in today’sthis action. Any comments related solely to the NSR 

program will be considered out 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 
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other rules recently finalized or proposed by the EPA rules41. 

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

(77 FR 9304; Feb. 16, 2012)42; the Cross-State Air Pollution Rule 

(CSAPR); Requirements for Cooling Water Intake Structures at 

Power Plants (79 FR 48300; Aug. 15, 2014); Disposal of Coal 

Combustion Residuals from Electric Utilities (CCR Rule), issued 

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

Limitation Guidelines and Standards (SE ELG Rule) (78 FR 34432; 

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

final Emission GuidelinesEGs along with steps the EPA is taking 

to enable compliance with obligations under other power sector 

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

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

the design and implementation of the federal plan that further 

this objective.

H.I. J. Administrative Appeals Process

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

 

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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the EPA anticipates that there may be situations in which 

individual parties are affected by decisions of the agency. For 

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

that an eligibility application by an ERC provider is denied. 

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

affected EGU may believe that its generation numbers 

wereallowance allocation amount was miscalculated. Similar to 

prior trading programs, the agency believes it would be 

efficient and potentially avoid the need for recourse to 

litigation, to provide an administrative appeals process.

Therefore we are proposing, and requesting comment on, the use 

of the regulations for appeals procedures set forth in 40 CFR 

Part 78, to provide for the adjudication of certain disputes 

that may arise during the course of implementation of a federal 

plan under 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 
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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 

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 calculationallocation of generation by 
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affected EGUs duringallowances from set-asides; decisions on the 

baseline period or compliance periodstransfer of allowances; 

decisions regarding the calculationfinalization of emissions

data by affected EGUs during compliance periods; decisions 

making error corrections to information submitted by affected 

EGUs and other account holders; decisions that there has been 

excess emissions requiring a 2-for-1 allowance administrative 

compliance penalty; and decisions regarding the deduction or 

surrender of allowances for compliance from affected EGUs’ 

compliance accounts. 

We request comment on this list of actions for both types 

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

decisions that may be made in the course of implementation of 

the federal plan that are party-specific that would be 

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

comment on whether it would be appropriate for the EPA to 

finalize an administrative appeals process that differs in any 

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

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

aspects of the alternative or additional adminsitrative appeals 

process, including with respect to any structural, procedural, 

subtantive, and timing requirements it should include, who 

should have access to it and in what manner, and how it would 
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differ from Part 78.

I.J. Consistency of Program Structure with Clean Air Act 

Authority 

The EPA is co-proposing two distinct forms of emissions 

trading as the mechanism for federal implementation of the 

standards of performance establishedthat achieve the emission 

performance levels by determined by application of the Best 

System of Emission Reduction (BSER) in the Emission Guidelines 

(Clean Power Plan EGs).. Both proposals are “emission standard” 

approaches as defined in the EGs, and the EPA is not proposing 

an approach like the “state measures” approach discussedthat is 

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

legal authority to establish either of the proposed trading 

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

this topic briefly here and invite public comment. The Emission 

GuidelinesEGs discussed the role of emissions trading in the 

BSER, see, e.g., &&& FR XXXX (XX XXXX) (“[Section V]iewed from 

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

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

compliance, which atpreamble to the level of implementation 

could be realized through trading of rate-based emission credits 

or mass-based emission allowances.”).final EGs. The EPA regards

this to be a separate issue and is not revisiting or reopening 
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the discussion of the BSER or the role of trading in the BSER 

here. The Emission GuidelinesEGs recognize and provide ample 

opportunity for states to establish standards of performance 

that allow the use of emissions trading or other multi-unit 

compliance approaches. Id. Here we discuss why an emissions 

trading program is a lawful and appropriate form of federal 

“implementation” of a "standard of performance" under section 

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

agency’s interpretation of its authority.

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

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

The Administrator shall have the same authority—

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

State fails to submit a satisfactory plan as he would have 

under section 7410(c) of this title [CAA section 110(c)] in 

the case of failure to submit an implementation plan, and 

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

where the State fails to enforce them as he would have 

under sections 7413 and 7414 of this title [CAA sections 

113 and 114] with respect to an implementation plan. 

In promulgating a standard of performance under a plan 

prescribed under this paragraph, the Administrator shall 

take into consideration, among other factors, the remaining 
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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 111(d) as, in some sense, coextensive with its authority to issue a federal implementation 

planFIP for NAAQS pollutants under section 110. This authority 

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

the purpose of that section (i.e., to establish standards of 

performanceto 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 Section 110 authority be looked to under 

section 111(d)(2). See 40 FR 53340, at 53342 (Nov. 17, 1975) 

(“It is obvious that [the Administrator] could only prescribe 

standards on some substantive basis. The references to section 

110 of the CAA suggest that (as in section 110) [she] was 

intended to do generally what the states in such cases should 

 

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

provision is discussed above in Section III.G.
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have done, which in turn suggests that (as in section 110) 

Congress intended the states to prescribe standards on some 

substantive basis. Thus, it seems clear that some substantive 

criterion was intended to govern not only the Administrator’s 

promulgation of standards but also [her] review of state 

plans.”). 

Over the several decades of implementation of the Clean Air 

Act, the courts, and the EPA, have addressed the nature and 

scope of section 110 authority. See, e.g., 71 FR 25328, 25338 

(May 12, 2005) (CAIR final rule). In general, the EPA has broad 

power under section 110(c) to cure a defective state 

implementation plan. Thus, in promulgating a federal 

implementation plan (FIP) under section 110, the EPA may 

exercise its own, independent regulatory authority in accordance 

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

promulgated a FIP, courts have not required explicit authority 

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

broad grant of power to the EPA as including all enforcement 

devices reasonably necessary to the achievement and maintenance 

of the goals established by the legislation.” South Terminal 

Corp. v. EPA, 504 F.2d 646, 669 (1st Cir. 1974). Further, the 

same authority that is exercised by the states under the CAA in

connection with the adoption, implementation, and enforcement of 
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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 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 

section 110(c) authority, those too, would arguably carry over 

to section 111(d)(2). For instance, section 110(c)(1) ties the 

EPA’s authority to promulgate a final FIP for a state to the

EPA’s predicate action on a state implementation plan (or lack 

thereof): generally, either an action disapproving a plan, or a 
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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 two-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 section 111(d)(2) as it possesses under 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 section 110 is informed by the 

scope of the state’s action to undertake a SIP; likewise, the 

scope of the EPA’s action to undertake a federal plan under 

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 

 

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

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

discussed in Section VII, below, the current version of section 

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

Amendments based on experience gained in the first two decades of 

the Act’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 section 111 as well.
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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, the EPA would set emission 

standards for each of the affected EGUs in the federal-plan state, 

provide mechanisms for their implementation and enforcement, and 

otherwise leave to the owners and operators of the affected EGUs 

the decisions about what measures they want to take to comply with 

the emission standard. Though the emission standards will be 

federally enforceable, as under a state plan, sources may achieve 

them through implementation of measures in the BSER, or any other 

method.

Thus, the question whether the EPA would have the authority 
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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 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 

enforceable standards of performance in the federal plan proposed

in this action, the agency is ensuring that these things will 

happen.
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2. Use of Market Techniques to Implement Standards of Performance 

under the Clean Air Act

The use of market techniques such as emission trading is 

well-supported in the Clean Air Act 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 section 111(d) in the Emissions Guidelines. 

[&&&cite XX FR XXXXX]. We adopt the same reasoning here, andSee 

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

with respect to the agency’s own authority under section 

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

“standard of performance” in the federal plan.

The 1990 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 

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

enforceable emission limitations and other control measures, 

means, or techniques (including economic incentives such as 

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

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

definition of a “Federal Implementation Plan” in section 302: 

“The term ‘Federal implementation plan’ means a plan (or portion 
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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) provides the EPA “the same 

power to prescribe” a federal plan under section 111 as it would 

have to promulgate a FIP under section 110(c). Thus, the EPA 

believes the plain language of the statute authorizes the use of 

market techniques in 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 section 111, the EPA believes that section 111, 

in conjunction with authorizations and endorsements of market 

techniques throughout the Act, 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 111(d). See also 40 CFR 60.21(f) (defining an 

“emission standard” as “a legally enforceable regulation setting 

forth an allowable rate of emissions into the atmosphere, 

establishing an allowance system, or prescribing equipment 

specifications for control of air pollution emissions.”); 40 CFR 

60.24(b)(1).
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Case law throughout the history of the CAA has generally 

confirmed the legal viability of emissions trading as an 

implementation measure so long as the trading ultimately 

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

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

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

area to attainment on basis that reductions in emissions from 

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

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

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

seminal case establishing the Supreme Court’s deferential 

standard of review of agency interpretations of the statutes 

they administer, upheld one of the EPA’s early emissions trading 

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

which the EPA in its discretion chose to allow states to apply 

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 
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approach in Chevron, the Supreme Court gave deference to the 

EPA’s definition of the term “source,” finding in that term 

sufficient ambiguity to support the agency’s reasoned 

application of an emissions averaging approach for total 

pollution emitted from the source. See EPA v. EME Homer City, 

134 S. Ct. 1584, 1603 (2014) (“Because ‘a full understanding of 

the force of the statutory policy . . . depend[s] upon more than 

ordinary knowledge’ of the situation, the administering agency’s 

construction is to be accorded ‘controlling weight unless . . . 

arbitrary, capricious, or manifestly contrary to the statute.’”) 

(quoting Chevron, 467 U.S. at 844).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 

 

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

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

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

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

goals of the Clean Air Act more quickly and inexpensively.” At 

the same time, based on lessons learned from its earlier 1982 

trading policy, the EPA took steps to tighten its policies on 

the use of “bubbles” to ensure environmental integrity of 

trading, particularly in non-attainment areas. The agency 

emphasized the requirements of enforceability, tracking (and 

preventing double-counting), determining the appropriate 

baseline from which to measure emissions, and demonstration of 

actual air quality benefits.

The use of an emissions trading system for CO2 reductions 

for affected EGUs under 111(d) is also analogous to the trading 

system for chlorofluorocarbons (CFCs) under the pre-1990 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 
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(April 14, 1989) (hereinafter “OLC Memo”).46 The OLC was asked by 

OMB to opine whether a general grant of regulatory authority to 

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

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

tradable allowances. The statute authorized the EPA to issue 

regulations “for the control of any substance, practice, 

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

judgment may reasonably be anticipated to affect the 

stratosphere, especially ozone in the stratosphere, if such 

effect in the stratosphere may reasonably be anticipated to 

endanger public health.” Former CAA 157(b) (as enacted in the 

1977 CAA amendments). The Office of Legal Counsel concluded that 

this language -- which it characterized as “plain,” 

“unambiguous,” and “sweeping” -- was sufficient to authorize the 

EPA to establish a cap-and-trade program with auction for CFCs. 

See id. at 7 (“It cannot seriously be argued that the use of 

economic incentives to regulate pollution is a novel or strange 

idea that could not have been anticipated by the authors of the 

Clean Air Act Amendments [of 1977].”) (citing multiple examples 

from the policy literature as early as E. Mishan, The Costs of 

Economic Growth (1967). The OLC noted that as of 1977, “Congress 

 

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

rulemaking.
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was cognizant of economic forms of regulation, did not prohibit 

them, but instead used general language permitting a wide scope 

of regulatory measures for the control of CFCs.” To interpret 

the general authority of this section of the CAA as 

affirmatively prohibiting market incentives would be, in the 

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

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

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

rewriting “unwarranted in any case, but especially so where 

Congress was aware of economic methods of control and where such 

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

Id.

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

Congress was comfortable enough with the efficacy of market 

techniques that they were broadly authorized for use in state 

and federal implementation plansFIPs for NAAQS. See 42 U.S.C. 

7410(a)(2)(A), 7602(y). In the wake of the 1990 Amendments, the

EPA issued an “Implementation Strategy for the Clean Air Act 

Amendments of 1990.”47 This Strategy included as one of nine 

overarching implementation principles, “Market-based: 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-based approaches and other innovative strategies to 

creatively solve environmental problems.” Further, it announced 

that the EPA would make “full use of innovative market-based 

approaches,” and that the agency will supplement traditional 

approaches with broader use of market incentives and other 

innovative approaches “whenever possible.” Id. at 3, 9.

Since the 1990 Amendments, the EPA has established three of 

its most robust trading programs – the Federal NOx Budget 

Trading Program (65 FR 2674; Jan. 18, 2000), the Clean Air 

Interstate Rule (CAIR) (71 FR 25328; April 28, 2006), and the 

Cross-State Air Pollution Rule (CSAPR) (76 FR 48208; Aug. 8, 

2011), under 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 Emission 

GuidelinesEGs, &&&cite&&&, the EPA has instituted or authorized 

the use of emissions trading programs twice in the past under 

 

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). 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 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 Clean Air Act 

going back decades amply support its decision to propose two 

forms of emission trading as the method of implementation of the 

carbon dioxide Emission GuidelinesClean Power Plan EGs in the 

federal plan. Notably, emissions trading is particularly 

 

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

requisite findings under 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 carbon dioxide, 

which is not a HAP under section 112.
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appropriate with respect to a global pollutant such as carbon 

dioxide that is well-mixed in the atmosphere and does not have 

direct, acute health impacts due to inhalation at ambient 

levels.50

Finally, the Supreme Court has affirmed the breadth of the 

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

which it would control carbon dioxide emissions 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 Clean Air Act entrusts such complex balancing to 

 

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 carbon dioxide 

emitted from affected EGUs. We address those concerns in the 

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

preamble in &&§ion IX below. 
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the EPA in the first instance, in combination with state 

regulators.”). 

Today’sThis proposal is guided by the relevant cases and 

the experiences of the agency in implementing the CAA trading 

programs discussed above. The EPA invites comment on this 

discussion and the agency’s interpretation that section 

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

proposed here.

IV. Rate-based Implementation Approach

A. Overview 

The EPA’s federal plan requirements for GHGsCO2 from 

affected EGUs implement the EGs as previously discussed. In this 

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

one option, rate-based emission standards (i.e., the emission 

standard approach) for affected EGUs not covered by an approved 

state plan as specified in the EGs. TheCPP EGs. 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 

CPP EGs, which included sub-categorized CO2 emission performance 

rates for affected EGUs to meet during the plan performance 
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periods. An affected EGU subject to this federal plan will 

demonstrate compliance by achieving a stack emission rate less 

than or equal to the rate-based emission standard or by applying 

ERCs, acquired by the EGU, to its measured stack emissions rate. 

The application of ERCs by an affected EGU to comply with an 

emission standard has been determined in the final CPP EGs as a 

mechanism available to affected EGUs with a CO2 emission rate 

greater than its respective performance rate to meet compliance 

obligations, see section IV.A.5.a [&&&] of the CPP EGs. Under a 

rate-based federal plan, the EPA would act as the state 

described in section VIII.C.3.a of the CPP [&&&] 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 how athe proposed rate-based federal 

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

operated, and how measures consistent with the CPP EGs building 

blocks can generate 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 certain nuclear generation that are measured by a 

revenue quality meter, rather than the full suite of options 

discussed in the emission guidelines. The EPA requests comment 
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on these means of generating ERCs and whether to limit the scope 

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

sources of low- or zero-emitting electricity not included in the 

building blocksin federal plan states should also be eligible to 

generate ERCs for compliance purposes. AFor both the proposed 

federal plan and model rule, the EPA requests comment on which 

EM&V plan, M&V report, and verification report requirements 

should apply for each eligible resource. Further discussion of 

non-BSER measures that may be ableeligible to generate ERCs can 

be found in the CPP EGs. and section IV.C.2 of this preamble.

(The EPA is not reopening its determination of the BSER.) In the

federal plan, the EPA is proposing to apply the subcategorized 

emission rates to the respective affected EGUs. The EPA is 

proposing a rate-based federal plan that uses the “emissions 

standards” option from the EGs.

B. Rate Goals

In the CPP EGs the EPA established the identified a ratebased “emission standards” approach as aan approvable method of 

compliance for state plans, while recognizing the availability 

of equivalent alternative methods of compliance to implement the 

final EGs. In this approach the requirements for compliance rest 

solely on affected EGUs in the form of federally enforceable 

emission standards. As noted above, this proposed rate-based
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federal plan adopts the “emission standards” approach. expressed 

as a rate of emissions of CO2 per unit of energy output. In the 

CPP EGs, the EPA established, through application of the BSER,

separate CO2 emission performance rates for affected EGUs in two 

subcategories. The two subcategories are natural gas-fired 

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

units, or NGCCsNGCC units) and fossil fuel fired steam 

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

CO2 emission performance rates set in the CPP EGs are reflected 

below in Table 4. The EPA is proposing to apply these rates in 

the rate-based federal plan as the emission standards for 

NGCCsNGCC units, and utility boiler/IGCCsteam generating units, 

respectively. For a thorough discussion of affected EGU

category-specific CO2 emission performance rates and rationale,

see Section VI &&& of the CPP EGs. These calculated 

limitsstandards and the premises that these limitsstandards are 

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

as they were finalized in the CPP EGs.

As discussed in section III.D above, the EPA proposes to 

implement a compliance schedule for the rate-based federal plan

with multi-year compliance periods as follows: A three-year 

 

51 For simplicity, affected utility boilers and IGCC units will 

collectively be called “steam generating units.”
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period (2022 through 2024), followed by a three-year period 

(2025 through 2027), followed by a two-year period (2028 and 

2029), for the interim period; and, commencing in 2030, 

successive two-year compliance periods for the final period. In 

the CPP EGs, the EPA established CO2 emission performance rates 

for the subcategories of affected EGUs for the performance 

periods. The EPA proposes to use those emission performance 

rates promulgated in the CPP EGs as the emission rate standard

for the respective EGUs that would become subejctsubject to this 

proposed federal plan if finalized. The EPA is not opening for 

comment the determinations, made in the CPP EGs, of each 

subcategorized CO2 emission performance rates. The emission rate 

standards for respective EGU types are provided for convenience 

in Table 4.

Table 4.The EPA is proposing to use a glide path during the 

interim period for EGUs to provide a smooth transition to the 

final compliance periods after 2030. This approach is described 

in section &&& of this preamble. In Table 4. below the 

applicable standards for each interim compliance period is 

listed.

Table 4. Glide Path Interim Performance Rates (Adjusted OutputWeighted-Average Pounds of CO2 Per Net MWh From All Affected 

Fossil Fuel-Fired EGUs) 
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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 most closely correlatesprovides an 

incentive structure, as compared to how the EPA envisionsother 

rate-based approaches, that facilitates implementation of 

measures identified as part of the BSER to function. . Using 

subcategorized rates allows for: (1) ana relatively equitable 

distribution of burden for emission reductions aross the 

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 broadly solicits comments on all 

 

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.
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aspects of the subcategorized rate approach.The EPA solicits 

comments on whether the subcategorized rate approach is the 

preferred rate-based approach for the federal plan and model 

trading rule.53 If a subcategorized approach for a rate-based 

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

EPA requests comment on the perceived benefits of an alternative 

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

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

emission standard).

C. Crediting Mechanism

Under a rate-based “emission standard” implementation

approach in the federal plan, we are proposing that EGUs subject 

to the emission performance requirements for GHGs will either 

need to emit at or below their emission rate standard, or they 

will need to acquire ERCs to achieve compliance. An ERC is a 

tradable compliance unit representing one MWh of electric 

generation (or reduced electricity use) with zero associated CO2

emissions. These ERCs may then be used to adjust the measured 

and reported CO2 emission rate of an affected EGU when 

demonstrating compliance with a rate-based emission standard. 

For each ERC, one MWh is added to the denominator of the 

 

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

BSER are not open for comment.
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reported CO2 emission rate, resulting in a lower adjusted CO2

emission rate.

Under this proposalproposed federal plan, ERCs will be 

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

affected EGUs that perform at a rate below the applicable 

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

REstandard; (2) affected NGCC units for all generation 

(represents shifting generation from steam generating units to 

NGCC units, as anticipated under Building Block 2); and (3) new 

nuclear units and capacity uprates at existing nuclear units,

and 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.6 of this 

preamble. We are also discussing in this preamble and, taking 

comment on for the federal plan, and proposing for the model 

trading rule a potential thirdfourth category: other low- and 

zero-emitting non-BSER measures that are described in section 

IV.C.2 of this preamble [&&&]. The concept of using an ERC as 

crediting mechanism to meet compliance obligations is consistent

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

 

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

the BSER emission performance rates is established in the CPP EGs 

section IV.A.5.a. [&&&]
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EGU Based ERC Generation

1. ERCs Generated and Owed Against a Standard

The number of ERCs generated or needed for surrender by an 

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

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

calculation of ERCs generated by an EGU or needed for compliance 

is the difference of the limit the EGU is subject to minus the 

CO2 stack emission rate of the EGU subtracted from the standard

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

divided by the limitstandard the EGU is subject to. This value 

is a normalized quantity of how much better or worse the EGU is 

performing compared to its standard. The normalized value is 

weighted by multiplying the MWh energyelectricity output from

the EGU at that the EGU is applying the limit to.emission rate.

This can be generically expressed as:

ERC MWhERCs

= (EGU limit − EGU operating rate)

EGU limit

(EGU standard − EGU operating rate)

EGU standard

∗ EGU generation

If the value calculated is positive, this indicates the number 

of ERCs that are being generated, and,; conversely, a negative 

value indicates how many ERCs will need to surrenderedbe

acquired to meet the unit’s emission rate for that compliance 
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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 &&& of this 

preamble.

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

interim compliance period is subject to a rate standard of 

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

and also assume it generates 1 million MWh over a compliance

period. Its total emission rate would be 2 billion lbs CO2 / 1 

million MWh. In order to achieve the emission standard, it would 

need to purchase 365,188333,334 ERCs (rounded to the nearest 

higher integer). In essence, this quantity of ERCs represents 

the quantity of MWh that need to be added to the steam EGU’s 

denominator (i.e., generation, here, 1 million MWh), such that 2 

billion pounds of CO2 (total emissions), divided by total 

generation (i.e., in this case, 1,365,188333,334 MWh) equals the 

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

quantity of ERCs for any given amount of generation can be 

easily calculated by dividing the total emissions of the 

affected EGU by the applicable emission rate limit, and then 

subtracting the generation of the affected EGU.
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To incentivize The discussion in this subsection builds on 

and captureapplies the definition, benefits, use, and 

determination of using ERCs from the CPP EGs Section VIII &&&. 

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 

carbon intensive rate. BB2 describes NGCC units generating at 75 

percent of the unit’s annual operating capacity. This means that 

most NGCC units are being called to increase annual generation 

from 2012 baseline emissions. For every hour of electricity 

generated by an NGCC beyond its 2012 baseline (i.e., incremental 

generation), there is a corresponding emission reduction in the 

power system.55 The EPA is proposing to reflect the emission 

reductions of Building Block 2 of the CPP EGs, the EPA proposes 

 

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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in the federal plan that NGCC generation has the capability to 

generate ERCs BB2 by crediting all NGCC generation on a pro-rata 

basis reflectingthat reflects expected incremental NGCC 

generation. Incremental to 75 percent capacity. This means 

that for every hour that an NGCC operation isgenerates 

electricity, it will also generate a credit associated with the 

relationship of an affected EGUs operation compared to the 

baseline year of 2012, used in setting the CO2 emission 

performance rates. Through Building Block 2 there is a call 

togeneration shift generation from fossil steam EGUs to NGCCs 

because NGCCs generate electricity at a lower carbon intensity 

and, thus, reduces CO2 emissions for the same level of 

generation56. To account for incremental generation the federal 

plan will use expected incremental operation of a NGCC in 

Building Block 2 of 75% to allow a NGCC to to NGCC units. The 

NGCC will generate ERCs for operation in relation to the 

incremental generation detailed in Building Block 2. a 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 

 

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

displacing fossil fuel-fired steam EGU generation.
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this subsection. 

All NGCC generation will be credited, with ERCs, by a 

factor that represents the described emission reductions from 

incremental generation; ERCs credited in this way will be 

designated as BB2Gas Shift ERCs (GS-ERCs) for clarity57. The 

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

of emission reductions described in Building Block 2BB2 when 75 

percent capacity is achieved. This incentive is not a 

requirement, however. If NGCCsNGCC units do not collectively 

meet theincrease to 75 percent capacity, the missed emission 

reductions or above, the lost opportunity for ERC generation 

simply will need to be achieved through other means (e.g.,

emissions performance improvements at affected EGUs or 

additional RE generation). The amount of BB2 GS-ERCs the EPA 

proposes to be generated for every MWh of NGCC operation is set 

at a factor relating the amount of electricity generation that 

NGCCsNGCC units collectively will need towould generate to 

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

reaching 75 percent capacity). ) and the associated emission 

 

57 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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reductions. This means that fractional BB2 GS-ERCs are generated 

for every NGCC MWh and when the interconnect region collectively 

reaches the level that would be generated if all NGGCs in the 

region operated at a 75 percent summer time capacity factor

there will be thean amount of BB2 GS-ERCs equatingthat 

correlates to the emission reductions calculated in building 

block 2reductionsanticipated under BB2 of the BSER. NGCCs NGCC 

units are expected to be incentivized to reach this level of 

generation because of in part due to market demand for them. BB2 

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

largean important role in the sector meeting compliance 

obligations. 

The BB2 ERC generating 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 and established in the BSER determination from the 

EGs of the least stringent region58 (i.e., the region with the 

 

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

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 additional MWhMWh beyond the 2012 baseline

needed for the corresponding region to reach 75 percent NGCC 

generation capacity and dividing it by the the MWh that is 75 

percent NGCC generation capacity, giving a factor. This factor 

is the rate at which BB2 ERCs are generated for every MWh of 

energy from an NGCC. This can also be expressed insummarized by

the following equationexpression:

Incremental Generation Factor = 1 − Regional 2012 NGCC Baseline

75 % NGCC Regional Capacity

The Incremental Generation Factor is a factor that the EPA will 

 

are the Eastern Interconnect, Western Interconnect, and Electric 

Reliability Council of Texas (ERCOT). 
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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).59 For the calculation of this factor the EPA is 

using the least stringent region for each compliance period and 

applying it for all GS-ERC calculations subject to the federal 

plan. The calculations for determinating the least stringent 

regional Incremental Generation Factor can be found in the &&& 

TSD. Table 5. below are the proposed values that would apply for 

all NGCC units to calculate the amount of issued GS-ERCs.

Table 5. Incremental Generation Factors for Interim and Final 

Compliance Periods 

Corresponding Incremental Generation Factor 

Compliance 

Period 1 

2022-2024

Compliance 

Period 2 

2025-2027

Compliance 

Period 3 

2028-2029

2030-2031

and thereafter

0.22 0.32 0.28 0.26

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

NN GGGGGG BBBB2 (MMMMh)

 

59 Note that per the discussion in Section VI of the CPP EGs, if 

the EPA had measured incremental NGCC generation for 

reassignment to fossil steam rate as the difference from the 

post building block three levels and full utilization, the post 

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

resulting in a higher “incremental generation factor” and more 

ERCs for the same amount of NGCC generation.
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The EPA has calculated this factor rate to be [&&&] 0.09 BB2 

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

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

The third factor in calculating an NGCC’s generaton of GSERC is the NGCC Generation. The NGCC Generation is the total net 

energy output generation of the affected NGCC during the year 

that ERCs are being calculated. The three factors combine to 

make the following equation:

GS-ERCs = NGCC Generation * Incremental Generation Factor * GS-ERC Emission Factor

The GS-ERC equation above gives the number of GS-ERCs that an 

NGCC will generate. The Incremental Generation Factor and GS-ERC 

Emission Factor combine to make the GS-ERC generating rate for 

the NGCC. This functions by the Incremental Generation Factor 

prorating all incremental NGCC generation and the GS-ERC 

Emission Factor designating the proportion of the incremental 

NGCC generation that will generate ERCs. The GS-ERC generating 

rate multiplied by the total NGCC Generation gives the total GSERCs generated by the NGCC for the year.

The EPA is proposing this approach, which provides GS-ERCs 

for all affected EGU NGCC generation but at a fractional, pro 

rated level, using the three factors above, for several reasons. 

This approach has the benefit of allowing NGCC units to bid into 

the electricity market without having to adjust bids based on a 
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projection of whether or not the NGCC will have generation 

incremental to its baseline in a given year. The proposed method 

also promotes the best performers within the NGCC subcategory by 

crediting them with a higher rate of generating GS-ERCs, as 

shown by the calculations above. The better the emission 

performance of an NGCC unit, the more GS-ERCs it is capable of 

earning per MWh. The proposed method also promotes and 

incentivizes all NGCC units, regardless of historical 

generation, to continue to operate at a greater capacity to 

replace steam generation. The EPA believes that this will allow 

for more fluidity in the market and flexibility for greater NGCC 

generation.

In the CPP EGs the BSER determination for subcategory rates 

is calculated by using the least stringent region and applying 

the standards from that region on a national level. The 

determination of the BSER in the final EGs was a one-time 

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 for all affected NGCC units subject to 
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the federal plan and model rule on a national level. The EPA 

also requests comment on applying, for each region, its own 

regional GS-ERC generation rate. As proposed, the least 

stringent region could change from compliance period to 

compliance period. The EPA requests comment on whether a single 

“least stringent” region should be chosen and used for 

calculations or whether being “least stringent” should be 

evaluated on a compliance period by compliance period basis. The 

EPA also requests comment on whether “least stringent” should be 

evaluated on a year to year basis. 

The EPA also requests comment on whether the GS-ERC 

Emission Factor should be calculated on a unit by unit basis (as 

currently proposed) or be calculated based on the least 

stringent region’s baseline 2012 average emission rate. This 

will simplify the practice of calculating and distributing GSERC generation, but would not reward the better performing NGCC 

units within the subcategory. In the &&& 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 EPA proposed, this would apply to every NGCC that 
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would be subject to the federal plan. 

In the &&&& 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 the 

NGCCits assigned emission standard for every MWh generated, but 

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

meet fossil steam generation units’ compliance obligations.

In the following example the EPA has taken the average NGCC 

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

of Building Block 2 to calculate an ERC generating factor for 

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

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

incremental operation of NGCC units across the system. The ERCs 

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

subject to the sub-categorized steam EGU CO2 emission performance 

rate.

In thisAs an example, an NGCC is connected to the grid and 

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

780771 lbs CO2/MWh. Since the NGCC is always subject to its NGCC

emission rate limitstandard of 780771 lbs/MWh and it is 

operating at a rate above that limitstandard it will owe non GSERCs for all generation. 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 llllll CC2lbs CO2 / [1,000,000 MMMMh + EEEEEE MMMMh]

= 780 llllll CC2[1,000,000 MWh + ERC MWh] = 771 lbs CO2/MMMMhMWh

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

the NGCC would need to acquire 89,744102,464 ERCs to adjust its 

emission rate to its emission rate standard.

Additionally, the BB2 ERC generationGS-ERC Emission Factor 

for this NGCC is calculated by using 771 lbs CO2/MWh for the NGCC 

emission rate, as determined by the [ref &&&] 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. 
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This is only an example. Because the Incremental Generation 

Factor is calculated by the EPA, is 0.09 BB2 ERCs/MWh of NGCC 

generation. Using this value the quantity of BB2 ERCs generated 

it can be calculated by the following equation:found in the &&& 

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. 

NN GGGGGGGGGGGGGGGG GG ∗ BBBB2 EEEEEE GGGGGGGGGGGGGGGG GG = BBBB2 EEEEEE

And to solve the equation for this example:

0.45 ∗ 0.26 ∗ 1,000,000 MMMMh ∗ 0.09

BBBB2 EEEEEE

MMMMh = BBBB2 EEEEEE = GS-ERC

The calculation results in 90117 thousand BB2 GS-ERCs being 

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

generates to meet its compliance obligations, this NGCC will 

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

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

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

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

proceeds may, in turn, be used to acquire non-BB2 GS-ERCs to 

satisfy the NGCC’s compliance obligations.

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

obligation because they are generated to reflect incremental 
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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 thisthe proposed approach and 

requests comment and suggestions on other approaches for 

existing NGCCsNGCC units to generate GS-ERCs at all times. The

EPA is considering this methodology that BB2 GS-ERCs are 

generated for all NGCC generation because it ensures that all 

existing NGCCsNGCC units are encouraged to run at a greater 

capacity. The EPA is requesting comment on alternative methods 

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

generating BB2 GS-ERCs once a threshold of electric generation 

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

emissions from 2012 foras a baseline and any NGCC generation 

beyond this threshold would be considered incremental 

generation. There are two different options to evaluate against 

a baseline. The first is on ana unit level, if ana NGCC 

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

2012 level (i.e, incremental generation) is eligible to be 

credited with BB2 GS-ERCs. The other threshold option is to use 
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a percentage threshold. This Evaluated on a regional level, the 

2012 baseline capacity percentage is the 2012 regional NGCC 

generation of total NGCC regional capacity in 2012. This 

percentagefor NGCC units in the least stringent region is 

applied at the unit level andto all generation by the NGCC 

thatunits. Each unit is considered to be incrementally 

generating after it exceeds that percentthe capacity at the NGCC 

is eligible topercent and will be credited with BB2 GS-ERCs

accordingly. The BB2 GS-ERCs in these instances are calculated 

by the following equation: 

BB2 ERCsGS-ERC

= (Steam standard − NGCC operating rate)

Steam standard

(Steam standard − NGCC emission rate)

Steam standard

∗ Incremental NGCC generation

This equation quantifies the reductions of the generation 

shift from fossil steam to NGCCsNGCC units by the NGCC operating 

rate being evaluated against the fossil steam standard. For all 

incremental NGCC generation the NGCC operating rate is compared 

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

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

against which BB2 GS-ERC generation is evaluated. An evaluation 

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

While having a baseline threshold for EGU generation to 

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

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

generated by displacingreplacing NGCC generation from one unit 

with other NGCC generation. from another. In this situation 

there is not necessarily any additional NGCC generation as a 

subcategory, but a shift in which NGCC units are generating 

electricity and to what degree. This allows for a situation in 

which BB2 GS-ERCs can be generated without necessarily 

corresponding to achieving the CO2 reductions anticipated by the 

BSER. Another aspect that reductions in CO2 emissions.

The EPA considered is proposing to use a a pro-rata 

approach for generating BB2 also requests comment on whether a 

distinct type of ERC that comes with the proposed restrictions 

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

electricity market without having to adjust bids based on 

projecting whether or not the NGCC will generate beyond a 

threshold. 

This discussion builds on and applies the definition, 

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

Section VIII. We invite comment on this approach as a 

methodnecessary to maintain the integrity of implementation of a 
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federal plan and a model the rate-based trading rule.proposal..

Comments regarding this section that solely relate to 

determinations finalized in the EGs will be considered out of 

scope.

1.3. Other Eligible Emission Reduction Measures offor ERC 

Generation

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

specify zero- and low-emittingemission reductions measures used 

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

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

RE capacity incremental to 2012 implementing 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 measure typesresources

(as specified in final guidelines Sec.V.E.) are eligible for 

rate-based creditingto be issued ERCs: on-shore wind, solar 

photovoltaics (PV), concentrated solar power, geothermal power, 

and hydropower.60 Further, the EPA is proposing that new nuclear 

 

60 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 as the 

federal plan, and all proposed aspects of the eligible measure 
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units and capacity uprates at existing nuclear units that meet 

the requirements for eligible resources in the emission 

guidelines (as specified in the final emission guidelines 

Sec.VIII.K.) and all other requirements related to ERC issuance 

in the emission guidelines and this proposal. Further, these RE 

and nuclear measures must have the capacityability to provide 

data from a revenue quality meter, a requirement which is 

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

Verification, provided below. This treatment for eligible 

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

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

proposed aspects of the eligible measure types described in this 

section and the requests for comment included below also apply 

in the mass-based set-aside context. The set-aside method IV.D.8

and the use of this eligibility treatment within it are 

specified in Sec. &&&.Sec. IV.G.4below.

The EPA is proposing the inclusion of these measure types 

for the following reasons. These technologies, with the 

 

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 setaside method and the use of this eligibility treatment within it 

are specified in Sec. &&&.
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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 Sec. V.E.). These technologies are also expected to be 

able to deploy on an economic basis during the compliance 

period, as discussed in the final EGs (see Sec. V.E.6). These 

technologies also provide the simplest and most timely path for 

evaluation, measurement, and verification (EM&V) implementation 

under a federal plan, as they can use their existing metering 

infrastructure to quantify generation and submit it for ERC 

issuance. This EM&V approach is allowable under the EM&V 

requirements in this proposal, outlined in Sec. &&&, and is 

consistent with the requirements outlined in the final 

guidelines (see Sec. VIII.&&&).A 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
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jurisdictions is ensured. This approach would allow for easier 

determinations of compliance with the requirements for EM&V 

proposed in Section IV.&&& below (see also Section VIII.&&& of 

the EGs).

The agency requests comment on the inclusion of other zeroand low- emittingemission reduction measures as eligible for ERC 

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

to assure suggested sources can be validated to assure 

reductions of CO2. This may include other RE technologies not 

included above, such as distributed RE generation and various 

types of biomass. In this proposal, the EPA is offering for 

comment various treatment options for different types of biomass 

fuels, 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 

inclusion of combined heat and power (CHP) as an eligible 

measure. 

The EPA requests comment on the inclusion of any other 

zero- or low-emitting measure typesemission reduction measures

beyond those mentioned here, as long as they meet the 
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eligibility requirements outlined in the final EGs for ratebased crediting. For all of the above measures on which the EPA 

requests comment, the agency is particularly interested in 

comments on how EM&V methods can be implemented for these

measures across applicable jurisdictions in the timeframe 

provided by this proposal in a way that is rigorous, 

straightforward, widely demonstrated, and in accordance with the 

EM&V requirements in this proposal, outlined in Sec. &&&, and 

within the requirements outlined in the final guidelines (see 

Sec. VIII.G.5). 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 

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 
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crediting. The EPA is also requesting comment on the following 

treatment options for biomass if biomass is included as an 

eligible measure. In the final emissions guidelines, the EPA 

recognizes that the use of some biomass-derived fuels can play 

an important role in controlling or reducing the contribution of

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

levels in the atmosphere (see Sec. I.2.c). 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.61 Many states have also recognized the importance of 

 

61 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 

anaerobic decomposition of biological materials; livestock waste; 

and the biogenic fraction of MSW at waste-to-energy facilities (as 

discussed in section VIII.G.1.b(3)(c) of the final emissions 

guidelines).
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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.62

In addition to acknowledging such state programs, the EPA 

has undertaken a technical assessment of biogenic CO2 emissions 

from stationary sources associated with the production, 

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

agency released a second draft of the technical report, 

Framework for Assessing Biogenic Carbon Dioxide for Stationary 

Sources. The revised Framework, and the EPA’s Science Advisory 

Board (SAB) peer review of the 2011 Draft Framework, 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 

 

62 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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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.63 The EPA is engaging in a second round of 

targeted peer review with the SAB in 2015.64 Information in the 

revised Framework and the second SAB peer review process, 

including stakeholder comments, will assist the EPA in assessing 

potential qualifying biomass feedstocks in federal plan 

applications. 

Provided for comment below are optionsIf biomass is 

included as an eligible measure, we are taking comment on an 

option for biomass treatment under the rate-based federal plan, 

which would also apply to eligible generation under the massbased plan allowance set-aside and to the calculation of covered 

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

include: .

• A list of specific acceptable biomass fuels 

• General principles and/or specific criteria regarding biomass 

fuel production, processing and use for energy

 

63www.epa.gov/climatechange/ghgemissions/biogenic-emissions.html.

64 www.epa.gov/sab. 
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• A combination of the above options. 

The firstThis option offered for comment is to specify a 

list of specific pre-approved acceptablequalified biomass fuels. 

For example, the EPA could recognize the biogenic CO2 emissions

and climate policy benefits of waste-derived (e.g., landfill 

gas) and certain industrial byproduct feedstocks (such as black 

liquor or other forestry and agricultural industrial byproducts 

with no alternative markets), based on the conclusions supported 

by a variety of technical studies. The). As another example, the 

EPA could also recognize feedstocks from sustainably managed 

forests lands, provided that these feedstocks meet certain 

requirements. The pre-approved qualified feedstocks list could 

be amended in the future as the science related to biogenic CO2

emissions assessments evolves. Also,The EPA asks for comment on 

whether to include a provision could be included that allows 

sources to seek approval for other types of 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 agriculturederived biomass fuels and related CO2 benefits.

The second option offered for comment would be to establish 

general principles and/or specific criteria concerning the 

production, processing and use of biomass fuels. These 
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principles or criteria would reflect sustainability and 

sustainable practices that enhance carbon sequestration and 

storage in a manner consistent with widely accepted principles. 

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

sustain, and enhance ecosystem health and vitality; maintain and 

enhance carbon sequestration and storage; ensure long term 

forest and landscape productivity and economic viability; 

protect culturally and environmentally sensitive areas; and 

employ rigorous monitoring and verification of carbon stock 

levels.

Under this option, the EPA could specify criteria for the 

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

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

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

conservation value areas, biodiverse areas, protected lands and 

other sensitive lands.

Examples of other potential criteria include:

• Improved management to increase carbon sequestration 

benefits and protect forest health, including the retention 

of recommended levels of slash, woody debris, crop and 

other biogenic materials from harvest/related activities.
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• Limitations on deforestation and targeted land use change, 

especially of high carbon and/or otherwise ecologically 

sensitive areas for the production of bioenergy feedstocks.

• Employment of sustainable management practices which 

promote production levels that can continue at a given 

intensity of management consistent with required 

environmental protection and which is professionally 

planned to achieve over time the desired balance between 

growth and removals on the landscape.

• Maintain soil and water quality and minimizing the amount 

of fertilizers and chemicals used on biomass fuel-producing 

lands through integrated pest and fuel management 

activities. 

• Use of the best scientific information and systems 

available to assess landscape health, carbon stock 

attributes and net carbon emissions attributable to 

production harvesting and use of biomass for combustion, 

and to continually refine and update inventories of these 

attributes. 

• Monitor and verify implementation of sustainable production 

and best management practices, including credible records 

and other evidence of management, monitoring and 
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verification activities. 

• Ensure forest and landscape productivity, and economic 

viability, including primary and secondary products. For 

example, if the biomass fuel is an industrial process 

residuals65, then the primary uses of sourced material (i.e. 

non-energy products) and related land use and industry 

practices remain intact. 

The third option offered for comment is a combination of 

the specific acceptable feedstock list and, for feedstocks not 

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

reflect sustainability and sustainable practices considered in a 

manner consistent with widely accepted principles.

The EPA also requests comment on options for demonstrating 

compliance with the options listed above that include criteria 

that reflect sustainability and sustainable that feedstocks meet 

the requirements to be accepted as a pre-approved qualified 

feedstocks. These requirements could include demonstration of 

certification or verification of practices that are additional 

to the other monitoring, reporting and EM&V requirements 

 

65 Industrial process residuals can be considered as substances that are not the 

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

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

the process has not been deliberately modified to produce it.
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discussed in section &&& above. These options for demonstration 

of compliance with criteria are described below. 

The first option offered for comment would require this 

proposal, such as provision of sufficient credible evidence, 

such as monitoring records and metrics showing that the 

forest/agricultural feedstock sources meet the criteria listed 

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

of non-compliance. 

The second option offered for comment would require the 

provision of approvedanalysis of carbon benefits, third party 

verification and/or certification entities or programs to 

demonstrate compliance with established sustainability criteria. 

Biomass that is acknowledged as sustainable and certified under 

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

Stewardship Council, Programme for the Endorsement of Forest 

Certification, Sustainable Forest Initiative], that is deemed or 

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

with the criteria offered for comment. These third party 

verifications can include demonstration of sustainable origin of 

feedstock (via chain of custody verification), mass balance 

calculations and/or other performance-based metrics. The EPA 

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

account when including acceptable certification programs or 
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criteria. The third option offered for comment allows for the 

use of any other verification programs or entities to 

demonstrate compliance which are not pre-approved but can be

proven to employ generally accepted sustainability metrics. For 

example, this would include verification programs that reflect 

sustainable production practices and responsible land use 

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

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

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

additional forms of records and metrics to verify feedstock 

sustainability.

The fourth option offered for comment requires , or a 

determination of the biogenic emissions and sequestration 

related to the production, processing and use of the biomass 

fuel, with supporting records. A potential calculation method is 

the application of an assessment framework like that provided in 

the 2014 Framework for Assessing Biogenic Carbon Dioxide for 

Stationary Sources that assesses the extent to which the 

production, processing, and use of biogenic material results in 

a net atmospheric contribution of net biogenic CO2 emissions. 

This type of method could use the actual measured (and verified) 

net biogenic CO2 emissions and sequestration values or biomass 

fuel-specific default values to calculate the carbon intensity 
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of the biomass fueleffects related to the production, processing 

and use of the feedstock. 

It is possible that compliance options could be implemented 

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

and/or verification entities and determination of biogenic 

emissions). 

The calculated carbon intensity of the biomass feedstock 

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

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

intensity of the feedstock in question could be used to 

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

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

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

monitor and report both its overall CO2 emissions and its 

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

emissions can be included in the calculation of the fossil rate 

at the affected EGU for the purpose of determining whether the 

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

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

calculated biogenic emissions. 

The eligibility requirements discussed in this section meet 
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the requirements outlined in the final EGs (See Final Emission 

Guidelines preamble section VIII.G.1.b: Actions taken to adjust 

the CO2 emission rate of an affected EGU).We take broad comment 

on the types of qualifying biomass feedstocks that should be 

specified in the final model rule, if any. We take comment on 

the methods that we should specify in the final model rule for 

the measurement of the associated biogenic CO2 for such 

feedstocks, as well as what other requirements we should specify 

in the final model rule related to biomass. Specifically, 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. We take comment on any other requirements that 

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

qualifying biomass. Discussion of the biomass EM&V requirements 

in the rate-based model rule can be found in Sec. IV.D.8 below. 

The eligibility requirements for ERC resources discussed in 

this Section meet the requirements outlined in the final EGs

(See Final EGs preamble section VIII.G.1.b). 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 
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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 

EPA’s existing data system. The ATCS would be used to track the 

trading of ERCs held by affected EGUs, as well as ERCs held by 

other entities. Specifically, the ATCS would track the 

generation of ERCs, holdings of ERCs in compliance accounts 

(i.e., accounts for affected EGUs) and general accounts (i.e.,

accounts for other entities and for affected EGUs part of, 

including affected EGUs that are under a ready-for-interstatetrading ready state plan), deduction of ERCs for compliance 

purposes, and transfers of ERCs between accounts. The primary 
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role of the ATCS is to provide an efficient, automated means for 

covered sources to comply, and for the EPA to determine whether 

covered sources are complying, with the emissions rate 

limitsstandards. The ATCS would also provide data to the ERCs 

market and the public, including a record of ownership of ERCs, 

dates of ERC issuance, ERC transfers, buyer and seller 

information, serial numbers of ERCs transferred, emissions, and 

compliance information. This information would be publicly 

available on the EPA’s web site and in annual progress reports.

The ATCS and the EPA provide all required elements of a 

qualified ERC tracking system as described in section VIII of 

the CPP EGs.

In the subsections that follow, the mechanisms by which a

rate-based trading program iswould be implemented and 

administered are detailed. This section elabrorates on this 

proposal, which implements through specific provisions the 

requirements for rate-based trading programs in the EGs. The EPA 

requests comment on each component of the trading system that is 

proposed in this preamble and the associated model rule, the 

trading program as a whole, and specifically requests 

commentscomment on means to expedite the process of issuing ERCs

and , any minimum and maximum periods for which ERCs should be 

issued (e.g., monthly, quarterly, annually), and any means to 
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insure the integrity that the ERCs issued meet the requirements 

of the ERCs that may be issued.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 would also 

describe the designated representative’s and alternate 

designated representative’s responsibilities and the process 

through which he or she could delegate to an agent the authority 

to make electronic submissions to the Administrator. These 

provisions would be patterned after the provisions concerning 

designated representatives and alternates in prior EPAadministered trading programs. 

The designated representative would be the individual 

authorized to represent the owners and operators of each 
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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 electric generating units at 

the source and for the designated representative and alternate; 

the name of every owner and operator of the affected EGU; and

certification language and signatures of the designated 

representative and alternate. All submissions (e.g., monitoring 

plans, monitoring system certifications, and allowance 

transfers) for an affected EGU would have to be submitted, 

signed, and certified by the designated representative or 

alternate. Further, upon receipt of a complete certificate of 
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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 

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 
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trading program. 

2. ERC Tracking and Compliance System 

The rate-based trading program rules establish the 

procedures and requirements for using and operating the 

Allowance Tracking and Compliance System (which is the 

electronic data system through which the Administrator would 

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

determining compliance with the ERC-holding requirements in an 

efficient and transparent manner. The ATCS provides a record of 

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

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

type (i.e., if it is BB2a GS-ERC or not). ERC price information 

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

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

obtain and disseminate timely, accurate price information than 

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

immediately reported to the Administrator for recordation, the 

Administrator would not be able to ensure that any reported 

price information associated with the transfers would reflect 

current market prices.

3. Tracking System Requirements

This federal plan and model rule’s proposed tracking system 

and tracking systems that will be presumptively approvable for 
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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,66 and an accompanying tracking system 

infrastructure design. Each issued ERC will have a unique 

identifier (i.e., serial number) and the tracking system will

provide traceability of issued ERCs back to the program or 

project for which they were issued. 

The EPA received a number of comments from states and 

stakeholders in the CPP EGs about 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 

 

66 “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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described above in section III.A, 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-interstatetrading to operate through a program in which the EPA provides 

the tracking and compliance system. This system will meet the 

requirements of the CPP EGs.

3.4. 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 

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 
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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. 

Averaging

4.5. 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 
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affected EGU to meet its compliance obligations its average 

stack emission rate over the compliance period must be at or 

below its applicable rate standard, or the affected EGU must use 

ERCs to adjust its average stack emission rate to be at or below 

its applicable rate standard. An EGU’s average emission rate 

over the compliance period will be calculated based on submitted 

data to ATCS. The compliance period average would be calculated 

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

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

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

the compliance period for that affected EGU produced. in units 

of MWh.67 This averaged emission rate will be compared to the 

emissions standards that the EGU is subject to during the 

corresponding interimcompliance period or final goal..

Accordingly, and if necessary, the appropriate number of ERCs 

will be deductedretired from the EGU’s compliance account to 

adjust the emission rate of the EGU to be equal to the emission 

standard. The discussion of using ERCs for compliance is found 

in section IV.D.8 of this preamble.

 

67 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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5.6. Recordation of ERC Generation and ERC Issuance

The EPA proposes to issue ERCs for ERC generating entities 

once per year. Thus, in a three-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 

issuance of ERC intervals.regardingERC-issuance intervals. We 

request comment on how reporting and recordkeeping requirements 

could be minimized for small entities to the extent possible 
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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 

rate68, the EPA will issue those ERCs into the affected EGU’s 

compliance account in ATCS. The issuance will occur annually 

through the NODA process. ERCs will have a unique serial number, 

tracking number, and will distinguish ERC type (i.e., if it is 

BB2 or not) when issued to an affected EGU.

b. Issuance of ERCs for RE, Demand-Side EE and Other Measures

Used to Adjust an Emission Rate

In the final EGs, the EPA has specified requirements for an 

ERC issuance process for the quantification and verification of 

RE and other measures used to adjust an emission rate that seeks 

to provide the necessary rigor and transparency while being 

efficient and streamlined. This is the intent of the federal 

plan as well., where there is a particular concern with 

implementing a streamlined and efficient federal process for ERC 

issuance across federal plan states. As required in the final 

EGs, we are proposing a two-step application process to the 

 

68 As described in section IV.C.1.
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federal plan tracking systems for RE ERCs.ERCs that allows for 

project approval to take place prior to the performance period, 

and makes the issuance of ERCs as quick and efficient as 

possible after generation has been quantified and verified, 

while still assuring a rigorous approval process. For the first 

step in the ERC issuance application process, the EPA proposes 

that RE and nuclear generation providers submit a project to the 

EPA an eligibility application for EPA approval to EPA, or its 

designated agent, demonstrating that the project is eligible for 

the issuance of credits, including an EM&V plan that meets EPA 

requirements. The EPA takes comment on all aspects of the 

proposed ERC issuance process. The EPA is also taking comment on 

how an ERC issuance process would apply to emission reduction 

measures for which we are taking comment regarding their 

eligibility for ERC issuance under the federal plan, including 

types of RE not covered by the federal plan, demand-side EE, 

CHP, biomass, and any other measure that could be considered 

eligible under the final guidelines.

The following are proposed required components of the 

projecteligibility application, as specified for these measures 

in the final emission guidelines:

(1) The EPA proposes that the federal plan will require 

that providers must show that the generation they would 
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be providing to the federal plan system for ERC issuance 

areis only being credited in the federal frameworkplan, 

and will not be submitted for ERC issuance in any other 

rate-based crediting system in any other state. As 

discussed in Section &&&IV.C. above, 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 Sec. &&&Section IV.C of this rule.

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

protocolplan that meets the federal plan requirements. 

Proposed requirements specific to the federal plan are 

proposed in Sec. &&&IV.D.6 of this rule. As specified in 

Sec. IV.D.8, we take comment on whether nuclear energy 

resources should be subject to the same EM&V requirements 

as renewable energy resources, and if not, we take 
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comment on to which EM&V requirements nuclear energy 

resources should be subject.

(4) There are special conditions if the provider is 

located in a state with a mass-based stateplan. For 

eligible RE capacity, the provider can only be credited 

in a rate-based state or rate-based 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. The EPA is proposing and show

that there is no other geographic limitation on the 

location ofmeasure was treated as a generation resource used 

to serve regional load that included the providers of 

RE.rate-based state. For incremental nuclear capacity, no 

provider in a state with a mass-based plan can be 

eligible for ERC issuance in a rate-based state. This 

requirement and the justification for its inclusion is 

further discussed in Sec.&&&.III.A. on Interstate Effects 

and also discussed in the Interstate Effects section of 

the final guidelines (Sec. VIII.G.2).VIII.L). The EPA is 

proposing that there is no other geographic limitation on 
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the location of the providers of RE and incremental 

nuclear generation under the federal plan. 

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

requirements, as is reflected in EM&V requirements for 

the final guidelines, and specified as part of proposed 

federal plan EM&V requirements belowin Sec. IV.D.6 of 

this rule. 

We request comment on each criterion of the eligibility 

application described herein and in the proposed model rule, 

for each eligible resource. Specifically, we seek comment on 

the substantive content of the criteria, and we seek comment 

on the level of detail provided and whether more or less 

detail (and what detail) should be included in the final model 

rule.

ERCs will be tracked in the Allowance Tracking and 

Compliance System (ATCS). Additionally, the EPA is proposing 

that the agency will establish a complementary tracking system 

for administering the rule that providesthe ERC issuance 

process. It will provide for transparent access to RE project 

and program eligibility applications and regulatory approvals 

as well as information on ERC transfers andthe activities of 

accredited third party verifiers (third party verifiers are 
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further discussed belowin Sec. IV.D.6 of this rule), as part 

of Evaluation, Measurement and Verification). well for the 

public to be able to generate reports based on this 

information.

The agency is proposing that thesethe project eligibility

applications will be accepted after the finalization of the 

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

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

that applications will be accepted on a periodican annual

basis. The agency requests comment on whether a quarterly or 

semi-annualbiannual application process is more appropriate. 

These applications will be accepted through the entirety of 

all compliance periods. The EPA will review and approve the 

project applications. It is proposed that the EPA may 

designate an agent to coordinate the project application 

process and assist with review of applications.

For the second step in the credit issuance application 

process, the EPA proposes that RE providers submit an 

application for ERC issuance M&V report to the EPA, or its 

designated agent, prior to the EPA’s issuance of ERCs. This 

can only occur after the approval of a project application, 

the RE has been generated, and necessary EM&V has been 

completed.
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The following are proposed required components of the 

creditERC issuance application:

(1) Documentation of completed EM&V in accordance with the 

EM&V plan submitted by the RE provider, including 

quantification of the MWh of generation to be credited 

and verification of their creation. This needs to meet 

the federal plan EM&V requirements outlined in Sec. &&&.

(2) Documentation that the generation has not been 

submitted for crediting under any other federal or state 

plan, including to another rate-based credit tracking 

system. This can be shown through a finding from a 

third-party verifier that meets federal plan 

requirements.

(3) Documentation that the MWh resulted from RE or 

incremental nuclear capacity eligible for crediting under 

the federal plan requirements and in accordance with 

final EGs.emission guidelines. This documentation should 

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

with a mass-based stateplan, and show if the generation 

is approved to be eligible for ERC issuance under the 

federal plan. See Section III.A.2&&& for specifics on the 

required demonstration for this type of RE generation. As 

discussed in that section, this option is proposed to not
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be available to incremental nuclear capacity located in a 

state with a mass-based plan.

(4) This application must include an a verification report 

from an independent third-party verifier, submitted after 

the verifier’s review and approval of all components of 

the application.the eligibility application, as is 

reflected in EM&V requirements for the final guidelines, 

and specified as part of proposed federal plan EM&V 

requirements described below and included in detail in 

the proposed model rule.

If the application meets these requirements, pursuant to 

review by EPA or its designated agent, ERCs will be issued to 

the provider by EPA through the federal plan credit tracking 

systemthe EPA or its designated agent, ERCs will be issued to 

the provider by the EPA through the Allowance Tracking and 

Compliance System (ATCS). The specific steps of the process by 

which an eligible resource seeks ERCs, and by which an 

affected EGU may use ERCs in its compliance demonstration are 

laid out in the proposed model rule. One of the steps requires 

the proponent to register for a general account in the EPA 

tracking system where the ERCs would be recorded. See section 

62.16515 for the requirements to establish a general account. 

While EPA is proposing to allow eligible resources to use a 
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general account to receive any ERCs issued under this section, 

EPA requests comment on extending the designated 

representative provisions in section 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 section 

62.16500 and to appoint a designated representative to act on 

behalf of all owners/operators for all projects requesting 

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

resources more accountable.

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

represents the actual MWh of energy generated or saved that it 

purports to represent, and as required in the emission 

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 
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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 above, we propose to use the 

administrative appeals process set forth 40 C.F.R. Part 78 to 

address party-specific disputes concerning the issuance and/or 

validity of ERCs. States may adopt a similar procedural and 

substantive process at the state level to enable them to 

rescind or withhold approval of specific credits. We request 

comment on the content of each of these provisions in the 

model rule, and specifically seek comment on whether the model 

rule should include different or additional details related to 

either procedure or substance for error correction and the 

revocation of the qualification status of an eligible resource 

or independent verifier.

The agency is proposing that ERC issuanceeligibility

applications will be accepted afterstarting before the 

beginning of the first compliance period, as soon as the 

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

application process, and the agency will establish and 

administer (unless delegated or taken over through a partial 

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

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

all compliance periods. The EPA will review and approve 

eligibility applicationapplications, and may designate an 

agent to coordinate and assist with credit issuanceERC 

eligibility applications. The EPA is proposing that ERC

issuanceit will issue ERCs for each compliancea given year 

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

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

may be necessary to accommodate the ERC issuance process, 

including necessary EM&V documentation... The overall proposed 

schedule for trading and true-up has been constructed to allow 

for this period of time for EM&V after the 

performancecompliance period.

The EPA proposes that certain pre-compliance measures are 

eligible for crediting reductions during compliance, in 

accordance with what is allowable under the final emissions 

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

after 2012 is eligible for ERC issuance for all of its

generation during the performance periods 2022-2030. This 

corresponds with treatment in the final emission guidelines, 

and ensures access to the RE generation assumed in CO2

emission performance rates and goals. 

Additionally, affected EGUs in jurisdictions subject to 
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the federal plan will be able to use rate-based ERCs or massbased allowances available from the clean energy investment 

pool, which rewards early action on implementing RE and 

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

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

&&&Placeholder for language on provisions to encourage 

early action that is being worked on offline&&& 

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 EPA in the context of the proposed federal 

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

that eligibility applications and monitoring and verification 

reports are appropriately reviewed prior to issuance of ERCs. 

Inclusion of an independent verification component is also 

consistent with similar approaches required by state PUCs for 

the review of demand-side EE program results and GHG offset 

provisions included in state GHG emission budget trading 

programs.
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The remainder of this section and the related language in 

the proposed model rule provide the proposed basis by which the 

EPA intends to evaluate the independence of the verifiers that 

it uses to provide verification reports pursuant to the federal 

plan. The qualifications described here and in the model rule 

would be presumptively approveable in the context of a state 

plan.

As a starting point, an independent verifier must have the 

necessary technical qualifications to provide verification 

services for the subject in question, as well as fulfill certain 

codes of conduct in providing verification services. Only 

verifiers approved or “accredited” by the EPA may provide 

verification services related to ERC issuance, in the same way 

that only verifiers approved by a state may be eligible to 

perform verification services pursuant to a state plan.69

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 

 

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

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

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

a principal or employee of a verification body.
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verifcation services related to the Clean Power Plan. Accredited 

verifiers must be independent. Accredited verifiers may not 

provide verification services for any eligible resource for 

which they have a financial, management, or other interest.70

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

 

70 Accredited verification bodies and individual verifiers may not 

have any direct or indirect organizational or personal 

relationships with an ERC provider that would impact their 

impartiality in assessing the validity and accuracy of the 

information in an eligibility application or M&V report. In 

addition to this general requirement, the following specific 

requirements also apply. Accredited verifiers must have no direct 

or indirect financial interest in, or other financial 

relationships with, an ERC provider or any related program or 

project that seeks issuance of ERCs. Accredited verifiers must 

have no relationship with the implementer of a program or project 

that seeks the issuance of ERCs, or any related ERC provider, that 

would represent a COI. Accredited verifiers must have no role in 

the development and implementation of a program or project that 

seeks issuance of ERCs, beyond the provision of verification 

services. Accredited verifiers must not be compensated, directly 

or indirectly, in relation to the quantified and verified MWh in 

an M&V report or on the basis of program or project approval, ERC 

issuance, or the number of ERCs issued. Accredited verifiers may 

not hold ERCs, or other financial derivatives related to ERCs, or 

have a financial relationship with other parties that hold ERCs or 

other related financial derivatives. Verification reports must 

include an attestation by the accredited verifier that it assessed 

potential COI related to an ERC provider and adequately addressed 

any identified COI.
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situations may also arise as a result of personal relationships 

among individuals representing an ERC provider and an accredited 

verifier. A verification report will not be accepted as part of 

an eligibility application or M&V report where the accredited 

verification body or any individual verifier has a COI. 

Accredited verification bodies must have management protocols in 

place to identify and remedy any COI prior to provision of 

verification services. that the proposed federal plan and model 

rule provide that failure of an accredited verifier to identify 

and adequately address any COI prior to provision of 

verification services is grounds for revocation of 

accreditation. The EPA will perform periodic reviews of 

accredited verifiers, to ensure that verifiers are maintaining 

necessary technical and professional qualifications and are 

meeting program requirements for provision of verification 

services. The EPA may recognize, in part, accreditation by an 

outside organization where such outside accreditation 

demonstrates that federal plan requirements are met.71 The EPA 

requests comment on the proposed necessary requirements for an 

 

71 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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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.

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

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

Reports

The EPA is proposing that issuance of ERCs to credit 

eligible measures requires the implementation and documentation 

of sufficient EM&V72. Such EM&V requirements, which reflect and 

are generally consistent with prevailing industry-standard 

practices, are specified in the final emissions guidelines (see 

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

 

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

analytic approaches used to quantify the MWh from RE and demandside EE, and thereby ensure that the resulting savings and 

generation are quantifiable and verifiable. In this proposal, we 

are proposing EM&V for the eligible RE, and taking comment on EM&V 

for demand-side EE and any other measures that could be eligible.
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issuance of ERCs under the federal plan meet the requirements 

specified in the final guidelines, with the following additional 

proposed requirements and specification of final emission 

guideline requirements.

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

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

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

satisfied under a federal plan. The following proposed federal 

plan requirements are drawn from that section. Proposed eligible 

measures for ERC issuance must all have the capacity to provide 

data from a revenue quality meter that meets the applicable ANSI 

C-12 standard or equivalent, which is the typical requirement 

for settlements with RTO and other control-area operators. These 

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

In this proposal we are requesting comment on the inclusion 

of other RE measures and demand-side EE measures as eligible 

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

measures are specified in detail in the final guidelines 

preamble Sec. VIII.G.5. For commentersThis 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 
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generate ERCs or otherwise adjust an emission rate.73

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 

 

73 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 

commentscomment on how the EPA could implement across applicable 

jurisdictions a rigorous, straightforward, and widely 

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

approaches that could be implemented in the time frame allowed 

by the federal plan and that also meetsmeet the requirements 

outlined in the final guidelines. To the extent proposed for 

inclusion in the model trading rule, we also invite comment on 

these requirements in the context of state implementation as 

part of a proposed model trading rule for states to use.state 

plan. Thus, commenters on this aspect of the proposal should 

consider whether and how these provisions could be implemented 

at the state level. The EGs set minimum requirements for ratebased programs, including ERC EM&V. Thus commentsComments that 

suggest an approach not authorized by the EGs maywill likely be

considered out of scope of this action to that extent. .

The final EGs provide requirements for independent 

verifiers, including standards for accreditation and eliminating 
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conflict of interest (see Sec. VIII.&&&). The EPA request 

comment on the specific requirements that third party verifiers 

should meet prior to participating in the federal plan ERC 

issuance process.

Additionally, with respect to EM&V, the EPA describes 

certain established industry best-practice methods, procedures, 

and appraoches that would be presumptively approvable if 

included in state plans. States wishing to adopt the model rule 

must submit these methods, procedures, and approaches as 

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

equivalent to the industry best-practices described as 

presumptively approvable.74

As discussed in section IV.C.3, 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 

 

74 The EPA recognizes that EM&V is routinely evolving to reflect 

changes in markets, technologies and data availability, and 

expects to update its EM&V guidance over time. Therefore the agency 

expects that alternative quantification approaches will emerge 

that can be approved for use, provided that such approaches are 

functionally equivalent to the provisions for EM&V outlined in 

this section. 
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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.75

a. Overall Approach and Measure-Specific Requirements

The proposed CPP EGs stated that the EPA would establish 

EM&V requirements and procedures to help states, sources, and 

resource providers quantify and verify MWh savings and 

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

efforts. This federal plan proposes those requirements that the 

EPA committed to establish. The CPP EGs proposal and associated 

“State Plans Considerations” TSD76 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 

 

75 A full discussion of applicable requirements for the 

establishment and functioning of the rate-based trading system is 

provided above, in section &&&.

76 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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and quality assurance approaches for over 30 years, particularly 

with regard to the quantification and verification of energy 

savings resulting from utility-administered EE programs. The EPA 

also observed that the majority of RE generation is typically 

quantified and verified using readily available, reliable, and 

transparent methods such as direct metering of MWh. The EPA is 

proposing EM&V methods, procedures, and approaches, described 

herein, that are intended to be consistent with and leverage 

prevailing industry best-practices.

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

and approaches reflect several overarching objectives and 

principles offered by states, private organizations, and the 

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

the importance of balancing the accuracy and reliability of 

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.2 of the 
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CPP 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 EPA, respectively, an EM&V plan that 

documents how requirements for quantification and verification 

will be addressed as EM&V is performed over the program or 

project period. After implementation has occurred, the ERC 

provider must submit periodic monitoring and verification (M&V)

reports to document and describe how each of the requirements 

were applied. These reports must also specify the resulting MWh 

savings or generation values, as determined on a retrospective 

(ex-post) or real-time basis. MWh values may not be determined 

using projections or other ex-ante quantification approaches. 

Each EM&V plan submitted in support of an eligibility 

application must identify the eligible resource covered by the 

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

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.
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Each M&V report submitted in support of the issuance of 

ERCs to a specific eligible resource must include specific 

criteria described here and in the proposed model rule. For the 

first M&V report submitted, a key component is documentation 

that the electricity-generating resources or electricity-saving 

measures were installed or implemented consistent with the 

description in the approved eligibility application. Each 

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

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

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

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

savings quantified and verified for the period covered by the 

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

capability of the eligible resource during the period covered by 

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

with the date on which the change occurred, and information 

sufficient to demonstrate whether the eligible resource 

continued to meet all eligibility requirements during the period 

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

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

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

Specifically, we seek comment on the substantive content of the 

criteria, and we seek comment on the level detail provided and 
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whether more or less detail (and what detail) should be included 

in the final model rule, and whether the criteria should differ 

for each eligible resource.

Each verification report submitted by an independent 

verifier in support of the issuance of ERCs to a specific 

eligible resource must address the criteria described here and 

in the proposed rule text. Each verification report must set 

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

all relevant requirements, information and data, including an 

assessment of any material misstatements or data discrepancies. 

Any verification report included as part of an eligibility 

application must further describe the review conducted by the 

verifier and verify the following: the eligibility of the 

resource to be issued ERCs; that the eligible resource exists 

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

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

requirements; and any other information required or that the 

verifier finds, in its professional opinion, is necessary to 

assess the accuracy of the subject of the verification report. 

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

also describe the review conducted by the verifier and verify

the following: the adequacy and validity of the information and 

data submitted to quantify eligible MWh of electric generation 
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or electricity savings during the period covered by the report, 

as well as all supporting information and data identified in the 

EM&V plan and M&V report; evaluate whether all generation or 

savings data is within a technically feasible range for that 

specific eligible resource (determined through a quality 

assurance and quality control check of the data); that the M&V 

report meets its requirements; and any other information 

required or that the verifier finds, in its professional 

opinion, is necessary to assess the accuracy of the subject of 

the verification report. The EPA takes broad comment on each of 

these criteria, as described here and in the proposed model 

rule. Specifically, we seek comment on the substantive content 

of the criteria, and we seek comment on the level 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 
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regions. The existing reports and documentation from existing 

tracking systems may serve as the substantive basis for a 

monitoring and verification report for RE.

b. Renewable Energy EM&V Requirements

This section describes the EM&V requirements associated 

with quantifying electricity generation from eligible RE and 

nuclear, and for documenting these requirements in EM&V plans 

and reports. Consistent with prevailing views expressed in 

public comments, the EPA’s requirements presume that the 

quantification of RE generation can leverage the infrastructure 

and documentation associated with the establishment of renewable 

energy 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 
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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 

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

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

reasonableness by the Agency, state or the REC registry. 

For reporting purposes, RE generation may be aggregated 

from multiple generators into a single MWh value for the group, 

provided the following requirements are met: each RE unit is 

uniquely identified in the federal tracking system, the 

nameplate capacity of each RE unit is less than 150 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. 
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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 

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 
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the provisions in the proposed model rule and any alternatives 

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

units have the same essential generation characteristics, in 

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

appropriate content of the definition of “essential generation 

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

determined on a resource by resource basis, or can generation 

from a group of wind turbines be aggregated with generation from 

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

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

nameplate capacity of less than 150 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.
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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 

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 
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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 renewable energy resource (including the relvant size 

and distribution of such resource) that qualifies for issuance 

of ERCs for use in Clean Power Plan compliance. We take comment 

on whether nuclear energy resources should be subject to the 

same EM&V requirements as renewable 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 
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electrical output associated with the CHP unit.77 The incremental 

rate would be relative to the applicable CO2 emission rate 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 limit rate) * CHP MWh 

output, where the ratio is limited to values between 0 and 1.

The CHP electrical emission rate is the net emission rate 

when the CHP unit’s thermal output emissions are deducted from

the CHP unit’s total emissions. It can be derived as follows

[CHP fuel input * fuel emission factor – (UTO/boiler 

efficiency) * fuel emission factor]/CHP MWh

In order to determine the incremental CO2 emission rate, a 

CHP unit would monitor requirements for CO2 emissions and energy 

output.78 The monitoring requirements are standard methods 

 

77 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. 

78 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 
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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 facilities79 with electric generating 

capacity greater than 25 MW would follow the same monitoring and 

reporting protocols for CO2 emissions and energy output as are 

required for affected EGU CHP units. These requirements are 

discussed in section IV.D.13. 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 

 

titled ‘EM&V requirements that apply to biomass RE facilities.’

79 A CHP facility may consist of one or more electric generators.
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greater than 25 MW, its EM&V plan must specify that it will meet 

the requirements that apply to an affected EGU under §62.16540 

of this subpart. 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 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 98 (§§ 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.
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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 biomass. We take broad comment on the types of 

qualifying biomass feedstocks that should be specified in the 

final model rule, if any. We take comment on the methods that we 

should specify in the final model rule for the measurement of 

the associated biogenic CO2 for such feedstocks, as well as what 

other requirements we should specify in the final model rule 

related to biomass. We take comment on any other requirements 

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

for qualifying biomass. Detailed discussion on the role of 

qualifying biomass feedstocks can be found in Sec. IV.C.3.

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 98 (§§ 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 
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that addresses the biogenic CO2 emissions from a waste-to-energy 

facility must follow the requirements for monitoring and 

reporting biogenic CO2 emissions from the facility that were 

approved by the EPA in connection with the specific state plan. 

As discussed in the final CPP EGs (see Sec.VIII.K.1), only 

the portion of electric generation at a waste-to-energy facility 

that is due to the biogenic content of the MSW may be used to 

generate ERCs or counted by a state towards its achievement of 

its obligations pursuant to this regulation. 

The EPA requests comment on all metering, measurement, 

verification, and other requirements included in this subsection 

with respect to WTE, including the appropriateness of their use 

for WTE. We take comment on whether a waste-to-energy resource

should be subject to the same EM&V as renewable 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 
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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 

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 
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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 

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.80 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 

 

80 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., www.seeaction.energy.gov. Or current 

version.
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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 

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 four year intervals for building 

energy codes and product standards; every one, two or three 

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 
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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 

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 website, 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 
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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 

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 
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(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 

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 losses81 will be quantified and 

 

81 T&D losses are defined as the difference between the quantified 
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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 

optimization82) 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. Energy Information Agency (EIA) 

State Electricity Profile.83

• How the duration of EE program or project electricity 

savings will be determined. This must be determined 

using industry best-practice protocols and procedures 

 

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).

82 More information about these technologies is in section VIII.F.1 

above.

83 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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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 

savings values will be assessed, and the rigor84 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 

 

84 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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draft EM&V guidance.

(4) Use of Energy Efficiency EM&V Protocols

In the CPP EG’s public comments, the EPA heard that EM&V 

protocols for demand-side EE are currently in wide use, and that 

they should be continued and encouraged. The agency agrees with 

this observation and is therefore proposing the application of 

industry best-practice protocols and procedures for demand-side 

EE. A 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 &&&, 
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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 

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 
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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 

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 
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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

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 
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savings values. 

We take comment on the minimum and maximum intervals (in 

years) over which electricity savings must be quantified, 

including those time intervals specified in the proposed model 

rule, and we take comment on any factors that must be taken into 

consideration when determining the appropriate time interval for 

specific EE programs, projects, or measures.

Because many states have different EE programs in place 

today, and we would expect them to 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 
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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 

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 
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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 

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 

US 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 
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include in the final model rule regarding EE EM&V.

h. Skill Certification Standards 

Using a skilled workforce to implement demand-side EE and 

RE projects and other measures intended to reduce CO2 emissions, 

and to evaluate, measure and verify the savings associated with 

EE projects or the additional generation from performance 

improvements at existing EGU’s are both important. Several 

commenters pointed out that skill certification standards can 

help to assure quality and credibility of demand-side EE,RE and 

other carbon emission reduction projects. The EPA also 

recognizes that a skilled workforce performing the EM&V is 

important to substantiate the authenticity of emissions 

reductions.

The EPA agrees that in conjunction with other EM&V 

measures discussed in this section, and in the context of the 

model trading rules although this is not an aspect needed for 

presumptive approvability, states are encouraged to include in 

their plan a description of how states will ensure that workers 

installing demand side EE and RE projects, or other measures 

intended to reduce CO2 emissions, as well as workers who perform 

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 
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aligned with a job task analysis and/or certification 

scheme;

• Engages with subject matter experts in the development 

of the job task analysis and/or certification schemes 

that represent appropriate qualifications, categories 

of the jobs, and levels of experience;

• Has clearly documented the process used to develop the 

job task analysis and/or certification schemes, 

covering such elements as the job description, 

knowledge, skills, and abilities; 

• Has pursued third-party accreditation aligned with 

consensus-based standards, for example ISO/IEC 17024 

or IREC 14732.

Examples of such entities include: parties aligned with the 

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
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measures.

7.9. ERC Transfers and Trading

All affected EGUs that may be subject to this proposed 

federal plan would be required to be a part of the allowance 

tracking and compliance system (ATCS) that the EPA runs, 

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

not allowances. To register to participate in the ATCS an 

affected EGU must submit designated representative information. 

More information on the designated representatives is described 

below in section IV.E.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 75.85 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 

 

85 See section IV.D.11 for more information.
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that are posted online would be publicly available. 

Non-EGU ERC generating sources are required to submit 

generation data annually (see &&& Section IV.F of this preamble 

for a comprehensive discussion of non-EGU ERC generating 

sources). The data must follow the EM&V procedures delineated in 

Section IV.F.4 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 in 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.86

The process for transferring ERCs from one account to 

another is quite simple. A transfer would be submitted 

 

86 This true-up process is further described in section IV.D.8 of 

this preamble
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providing, in a format prescribed by the agency, the account 

numbers of the accounts involved, the serial numbers of the ERCs 

involved, and the name and signature of the transferring 

authorized account representative or alternate. If the transfer 

form containing all the required information were submitted to 

the EPA and, when the Administrator attempted to record the 

transfer, the transferor account included the ERCs identified in 

the form, the Administrator would record the transfer by moving 

the ERCs from the transferor account to the transferee account 

within 5 business days of the receipt of the transfer form. 

8.10. 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 deadline87 for that first compliance period (after which 

 

87 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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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 

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. This account 

available for the public to view. The EPA promotes transparency 

throughout the entire process. ERCs that are deducted for 

compliance will remain in the system in an EPA account, which 

ensures they will not be used again.

The EPA will use the submitted generation, CO2 emissions and 
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ERCs in the affected EGU’s compliance account to calculate an 

average emission rate for the EGU. It is the responsibility of 

an affected EGU to calculate the number of ERCs that will need 

to be held in a compliance account to meet the EGU’s compliance 

obligations. The method for determining the quantity of ERCs 

needed to meet compliance obligations has been discussed 

previously in an example. To reiterate the process, the affected 

EGU would need to solve for the number of zero-emitting MWh 

(i.e., ERCs) that would need to be added to the total MWh of the 

EGU to make the adjusted emission rate equal to the emission 

standard. 

AAAAAAAA AA EEEE = MM oo CC2 (llllll)

GGGGGGGG (MMMMh) + MMMMh EEEEEE

This equation can be rearranged to:

MMMMh EEEEEE = MM oo CC2 (llllll)

AAAAAAAA AA EEEE ( llllll

MMMMh)

− GGGGGGGGGGGGGGGG GG (MMMMh)

If an affected EGU fails to hold sufficient ERCs to comply 

with its emission standard then, upon notification of the 

deficiency, the owners and operators of the affected EGU must 

provide, for deduction by the Administrator, two ERCs as soon as 

available for every ERC that the owners and operators failed to 

hold as required to cover emissions, in addition to the ERCs 

owed for compliance in that next period. The owed ERCs will be 
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deducted from the EGU’s compliance account as soon as they are 

available in this account; the Administrator will not wait until 

the next true-up date to make this deduction. The two ERCs owed 

for each ERC needed for compliance is in addition to any other 

recourse provided in Sections 113 (a) – (h) or Section 304 of 

the Clean Air Act. This requirement to surrender two times the 

ERCs needed to make up the shortfall for the prior period is an 

ongoing obligation until compliance is achieved, and there is an 

ongoing obligation to comply in the current period. Failure to 

surrender these replacement ERCs is an additional violation that 

may be subject to federal enforcement. The EPA solicits comment 

on sources owing two ERCs to make up for each insufficient ERC 

in previous compliance periods and whether two for one is the 

proper make-up rate or whether there should be a stricter or a 

more lenient ratio. 

The EPA believes that it is important to include a 

requirement for an automatic deduction of ERCs. The deduction of 

one ERC per ERC that the owners and operators failed to hold 

would offset this failure. The deduction of another ERC per ERC 

that the owners and operators failed to hold provides a strong 

incentive for compliance with the ERC-holding requirement by 

ensuring that non-compliance would be a significantly more 

expensive option than compliance. This is consistent with other 
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existing trading programs.

9.11. Other ERC Tracking and Compliance Operations Provisions

These sections also would provide that the Administrator 

could, at his or her discretion and on his or her own motion and 

consistent with existing federal trading programs, correct any 

type of error that he or she finds in an account in the ATCS. In 

addition, the Administrator could review any submission under 

the rate-based trading program, make adjustments to the 

information in the submission, and deduct or transfer ERCs based 

on such adjusted information. These provisions are a standard 

part of other trading programs administered by the EPA including 

the 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. 

10.12. Banking of ERCs

The EPA is allowingproposing to allow unlimited banking or 

ERCs within and between the interim and final compliance 

periods. This means that if an affected EGU has more ERCs than 

are necessary during true-up, it may save (i.e., bank) those 

ERCs for application during a future compliance period. The EPA 

requests comment on whether there should be a quantitative limit 

or cap on the number of ERCs that can be banked. The EPA also 
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requests comment on whether an ERC should be eligible to be 

banked between the interim and final compliance periods. The EPA 

is also proposing that ERCs will not expire after any duration 

of time. The EPA requests comment on the shelf-life of an ERC. 

ERC “borrowing” is a flexibility that the EPA is not 

proposing, but is soliciting comment on. ERC borrowing is the 

concept that an affected EGU may use an ERC that the EGU will 

acquire in a future compliance period to meet its current 

compliance obligations. The EPA requests comment on a 

methodology that would allow ERC borrowing while maintaining the 

integrity of the compliance obligations. The EPA also has 

reservations due to the fact that future ERC generation is not 

guaranteed. 

11.13. Emissions Monitoring and Reporting

The EPA would require that ERCemission and generation data 

be reported to the EPA quarterly starting on April 30, 2022, and 

continuing every three 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 
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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 Part 75.60. The use of Part 75 certified monitoring 

methodologies would be required. Many affected EGUs that might 

be covered by the proposed federal plans will generally have no 

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 Mercury and Air Toxics Standards (MATS) program 

and therefore will have already installed stack flow rate and/or 

CO2 monitors in order to comply with the MATS rule which are also 

necessary to comply with this rule. The CEMS used to comply and 

report data for MATS will be used for this rule to generate and 

report CO2 emissions data without having to install duplicative 
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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 

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 the monitoring and reporting would be required in 

2021 — compliance with the requirement to hold allowancesan 

enforceable emission standard would commence on the compliance 
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period schedule that is detailed in section IV.E.3.

E. Federal Plan and State Plan Interactions

1. Interstate Trading

The EPA proposes that all affected EGUs within states that 

are covered by the federal plan, if a rate-based federal plan is 

finalized for two or more states, would be allowed to trade with 

one another since there will be an assured commonality in the 

ERC currency and criteria surrounding the trading program. In 

addition, the EPA proposes, consistent with the provision for 

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

the EGs that affected EGUs located in states with approved

ready-for-interstate-trading state plans using the subcategorized uniform rate standards, and a common credit currency 

(i.e., ERCs representing one zero-emitting MWh) may trade with 

affected EGUs operating under the federal trading program 

established in this federal plan. 

Rate-based EGUs subject to the federal plan and rate-based 

EGUs in presumptively approvableready-for-interstate-trading

state plans will be able to trade ERCs seamlessly across 

jurisdictional borders because of the assurances of being 

presumptively approvable. Presumptively approvableReady-forinterstate-trading states must submit information that lists all 

affected EGUs and the EGU type to the Administrator to be able 
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to trade within the federal trading program. To be able to trade 

in the federal trading program an affected EGU that is subject 

to a presumptively approvableready-for-interstate-trading state 

plan must: (1) certify and authorize a designated representative

per Section &&& IV.E.1 of this preamble; and (2) register a 

general account in the federal trading program, ATCS, in order 

to have a means of transferring ERCs with entities operating in 

the federal trading program. An affected EGU under a state plan 

will not register a compliance account in the federal system 

because it will not be demonstrating compliance under the 

federal plan. Compliance will be achieved in the EGU’s 

corresponding state plan. Affected EGUs under a state plan have 

the ability to acquire ERCs through the federal trading program. 

These ERCs will be stored in the EGU’s general account in the 

federal trading program. To use these ERCs for compliance 

purposes, the ERCs must be transferred to the EGU’s compliance 

account in the state’s program. The EPA proposes to provide 

software to states to maintain a state’s compliance and tracking 

program. A state’s program will have the capability to interact 

with the federal trading program and software, ATCS, for 

transferring ERCs if the state is presumptively 

approvable.ready-for-interstate-trading. A state’s program can 

be tailored to meet its needs while still providing a platform
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for a state to be transferring ERCs between the state’s system 

and the federal trading program. ERCs can flow between a state 

system and the federal trading program bilaterally. The EPA 

acknowledges that states may have additional criteria for 

generating ERCs that are not outlined as part of the federal 

plan, but because the EPA will have vetted these criteria 

through a state plan approval these ERCs will be able to be 

traded within the federal trading program. 

The EPA requests comment on a broader approach that would 

allow all affected EGUs that are located in states with approved 

rate-based state plans to participate in the federal plan 

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

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

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

for affected EGUs that are different from the national uniform 

subcategorized rates. We request comment specifically on what 

conditions or requirements would be needed in these cases in 

order to participate in the federal plan trading program in a 

way that is administratively feasible and maintains the 

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

serious concerns about the administrative complexity of this 

approach, we also request comment on the feasibility and 

potential mechanism of allowing EGUs in states with approved 
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mass-based state plans to participate in a federal rate-based 

trading plan. 

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

The EPA proposes that a rate-based trading federal plan may

be replaced by a state plan for a future compliance period. The 

EPA is proposing that a state must transition to a state plan at 

the conclustionconclusion of a federal plan compliance period. 

The EPA requests comment on whether there are reasons that a 

state should be allowed to transition from a federal plan to a 

state plan in the middle of a compliance period and if so what 

requirements should be put in place to do so while ensuring the 

integrity of both the federal plan and the state plan and while 

enabling the affected EGUs covered by the plans to understand 

and meet their compliance requirements. If a state subject to 

the federal plan transitions to a state plan, any affected EGU 

impacted by the change remains responsible for meeting any 

outstanding obligations under the federal plan. To make the 

transition to a state plan, a state must have an approved state 

plan as laid out in the CPP preamble section VIII.D and VIII.E. 

V. Mass-based Implementation Approach

A. Trading Program Overview

In addition to the rate-based implementation approach 
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discussed above, the EPA is proposing a mass-based 

implementation approach for the federal plan. As with the ratebased approach, this proposed federal plan is also a proposed 

model trading rule that states can adopt. The mass-based 

approach that the agency proposes to implement is a mass-based 

trading program (i.e., an emissions budget trading program, also 

referred to as an “allowance system”). This section provides a 

brief overview of the proposed mass-based trading program. The 

next sections describe the various elements of the proposed 

trading program in further detail.

A mass-based trading program establishes an “aggregate 

emissions limit” that specifies the maximum amount of emissions 

authorized from affected EGUs included in the program, and 

creates allowances that authorize a specific quantity of 

emissions. The total number of allowances created are equal to, 

and constitute, the emissions budget or the aggregated emissions 

limit expressed in terms of metricshort tons of emissions. The 

EPA is proposing that allowances be issued in metricshort tons

for the federal plan, and also requesting comment on the 

issuance of allowances in short tons..

Each facility with affected EGUs in the program must 

surrender allowances equal in number to the quantity of the

emissions of its affected EGUs during the compliance period. A
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facility with affected EGUs may buy allowances from, or transfer 

or sell allowances to, other affected EGUs or other entities 

that participate in the market. A mass-based trading program 

provides sources with great flexibility in choosing compliance 

strategies.

In the proposed mass-based trading program for the federal 

plan, the aggregate emissions limit for a state is its statewide 

mass-based emission goal (or “mass goal”) as finalized in the 

Clean Power Plan EGs. The proposed approach to linking states 

for interstate allowance trading is detailed in section III.A.1;

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, above), and 

affected EGUs and other entities in any state covered by the 
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federal plan mass-based trading program.

A mass-based trading program can provide environmental 

certainty at lower cost than other policy mechanisms, because it 

assures the specified emissions outcome while maximizing 

compliance flexibility available to individual affected EGUs. 

Further, allowance banking in such a program creates an 

incentive to make reductions earlier than required. Mass-based 

trading programs are relatively simple to operate, which reduces 

administrative time and cost. Additionally, to inform the massbased trading approach proposed here, the EPA draws upon more 

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

including the Acid Rain Program SO2 trading program, the NOX

Budget Trading Program, the Clean Air Interstate Rule, and the 

Cross-State Air Pollution Rule.

In the proposed mass-based trading program federal plans, 

the emissions limits in each state would be the mass goals that 

the EPA promulgated in the Clean Power Plan EGs (if there is 

interstate trading then the sum of the mass goals for the states 

in the trading program would constitute the aggregate emissions 

limit). The total amount of allowances distributed in each state

for each year would sum to the state’s mass goal for that year. 

As detailed in section V.E of this preamble, the EPA is 
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proposing that a state covered by the federal plan can determine 

its own approach to distribute allowances, and believes that 

state allocation has important merits. The EPA would distribute 

allowances in a state if the state does not choose to do so, as 

detailed below.

Each allowance would authorize the emission of one 

metricshort ton of CO2 during the compliance period applicable to 

the allowance’s vintage year or a later compliance period. The 

proposed approach to distribute allowances, including twothree

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

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] for the proposed length of the multi-year

compliance periods... Allowances could be transferred, bought, 

sold, or banked (carried over for future use) and any party 

could participate in the allowance market. The EPA is not 

proposing allowance “borrowing” (i.e., the bringing forward of 

future-period allowances for use in an earlier period); the 

multi-year compliance periods inherently provide the flexibility 

to schedule relatively greater emission reductions for later 

years within each period, as discussed further in section V.C. 
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In the proposed mass-based trading program, the emission 

standard applied to individual affected EGUs is the requirement 

to surrender emission allowances equal to reported emissions for 

each compliance period.

The EPA also proposes that a state may choose to replace 

the federal-plan allowance-distribution provisions with its own 

allowance-distribution provisions (i.e., to determine the 

distribution of allowances for its EGUs or other entities) using 

a state allowance-distribution methodology. State allowance 

distribution can have important advantages, because it allows a 

state to design and shape allowance allocation to its specific 

goals and characteristics, and because states may have 

additional flexibility on allocation approaches, including 

auctions. See section V.E 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.F 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
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identify qualifying biomass and provide a methodology for the 

treatment of biomass feedstocks (i.e., biomass feedstocks that 

are demonstrated to assign zero or partial emissionsbe a method

to qualifying biomass),control increases of CO2 levels in the 

atmosphere) and potential methods for demonstrating compliance,

and thus reduce the mass emissions attributed to a biomass cofired affected EGU. If the EPA took such an approach, then for 

purposes of compliance with the proposed mass-based federal plan 

trading program, the affected EGU would need to hold allowances 

equal to its emissions after reflectingless the zero or partial 

emissions attributed to the co-fired qualified biomass; such an 

approach 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,

below, the EPA proposes to implement the mass-based 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 twoyear compliance period in the Interim Period, and successive 
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two-year periods in the Final Period. In the Clean Power Plan 

EGs, the EPA established mass goals for all states for this 

pattern of compliance periods. The EPA proposes to use those 

mass goals promulgated in the Clean Power Plan EGs as the mass 

limits (i.e., emissions budgets) for any state covered by the 

mass-based trading program (or, if implementing interstate 

trading, then the EPA would use the sum of a covered group of 

states’ mass goals as the aggregate mass limit). The EPA is not 

opening for comment the determinations, made in the Clean Power 

Plan EGs, of each state’s mass goals. The mass goals are 

provided for convenience in Table ___ .

Table ___ Statewide Mass-based Emission Goals (“Mass Goals”)

(metric tons)

(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 
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Delaware

 

5,348,363 

 

4,963,102 

 

4,784,280 

 

4,711,825 

Florida

 

119,380,477 

 

110,754,683 

 

106,736,177 

 

105,094,704 

Georgia

 

54,257,931 

 

49,855,082 

 

47,534,817 

 

46,346,846 

Idaho

 

1,615,518 

 

1,522,826 

 

1,493,052 

 

1,492,856 

Illinois

 

80,396,108 

 

73,124,936 

 

68,921,937 

 

66,477,157 

Indiana

 

92,010,787 

 

83,700,336 

 

78,901,574 

 

76,113,835 

Iowa

 

30,408,352 

 

27,615,429 

 

25,981,975 

 

25,018,136 

Kansas

 

26,763,719 

 

24,295,773 

 

22,848,095 

 

21,990,826 

Kentucky

 

76,757,356 

 

69,698,851 

 

65,566,898 

 

63,126,121 

Lands of the Fort Mojave 

Tribe

 

636,876 

 

600,334 

 

588,596 

 

588,519 

Lands of the Navajo Nation

 

26,449,393 

 

23,999,556 

 

22,557,749 

 

21,700,587 

Lands of the Uintah and Ouray 

Reservation

 

2,758,744 

 

2,503,220 

 

2,352,835 

 

2,263,431 

Louisiana

 

42,035,202 

 

38,461,163 

 

36,496,707 

 

35,427,023 

Maine

 

2,251,173 

 

2,119,865 

 

2,076,179 

 

2,073,942 

Maryland

 

17,447,354 

 

15,842,485 

 

14,902,826 

 

14,347,628 

Massachusetts

 

13,360,735 

 

12,511,985 

 

12,181,628 

 

12,104,747 

Michigan

 

56,854,256 

 

51,893,556 

 

49,106,884 

 

47,544,064 

Minnesota

 

27,303,150 

 

24,868,570 

 

23,476,788 

 

22,678,368 

Mississippi

 

28,940,675 

 

26,790,683 

 

25,756,215 

 

25,304,337 

Missouri

 

67,312,915 

 

61,158,279 

 

57,570,942 

 

55,462,884 

Montana

 

13,776,601 

 

12,500,563 

 

11,749,574 

 

11,303,107 

Nebraska

 

22,246,365 

 

20,192,820 

 

18,987,285 

 

18,272,739 

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 
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New Jersey

 

18,241,502 

 

17,107,548 

 

16,681,949 

 

16,599,745 

New Mexico

 

14,789,981 

 

13,514,670 

 

12,805,266 

 

12,412,602 

New York

 

35,493,488 

 

32,932,763 

 

31,741,940 

 

31,257,429 

North Carolina

 

60,975,831 

 

55,749,239 

 

52,856,495 

 

51,266,234 

North Dakota

 

25,453,173 

 

23,095,610 

 

21,708,108 

 

20,883,232 

Ohio

 

88,512,313 

 

80,704,944 

 

76,280,168 

 

73,769,806 

Oklahoma

 

47,577,611 

 

43,665,021 

 

41,577,379 

 

40,488,199 

Oregon

 

9,097,720 

 

8,477,658 

 

8,209,589 

 

8,118,654 

Pennsylvania

 

106,082,757 

 

97,204,723 

 

92,392,088 

 

89,822,308 

Rhode Island

 

3,811,632 

 

3,592,937 

 

3,522,686 

 

3,522,225 

South Carolina

 

31,025,518 

 

28,336,836 

 

26,834,962 

 

25,998,968 

South Dakota

 

4,231,184 

 

3,862,401 

 

3,655,422 

 

3,539,481 

Tennessee

 

34,118,301 

 

31,079,178 

 

29,343,221 

 

28,348,396 

Texas

 

221,613,296 

 

203,728,060 

 

194,351,330 

 

189,588,842 

Utah

 

28,479,805 

 

25,981,970 

 

24,572,858 

 

23,778,193 

Virginia

 

31,290,209 

 

28,990,999 

 

27,898,475 

 

27,433,111 

Washington

 

12,395,697 

 

11,441,137 

 

10,963,576 

 

10,739,172 

West Virginia

 

62,557,024 

 

56,762,771 

 

53,352,666 

 

51,325,342 

Wisconsin

 

33,505,657 

 

30,571,326 

 

28,917,949 

 

27,986,988 

Wyoming

 

38,528,498 

 

34,967,826 

 

32,875,725 

 

31,634,412 

C. Compliance Timing and Allowance Banking

The EPA proposes to evaluate compliance (i.e., compare 

emissions from affected EGUs to allowances held by facilities) 
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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 

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 three-year compliance period (2022 through 

2024), a second three-year compliance period (2025 through 

2027), and then a two-year compliance period (2028 and 2029), 

for the Interim Period. As in the EGs, the Final Period would be 

divided into successive two-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 three 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 
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(RGGI) uses three-year compliance periods, along with 

interimintervening compliance periods.requirements. The RGGI 

interimintervening compliance period is a requirement foris that

sources tomust hold allowances to cover 50 percent of emissions 

for the first two calendar years of each three-year compliance 

period; at the end of each three-year compliance period sources 

must hold allowances to cover 100 percent of emissions for the 

period and allowances already deducted for the interim 

periodintervening requirement are subtracted from the three-year 

obligation.88 The California Air Resources Board (CARB) Cap-andTrade Program also uses three-year compliance periods, along 

with interimintervening compliance periodsrequirements. The CARB 

interim compliance period evaluatesintervening requirement is to

evaluate compliance on 30 percent of each source’s previous 

year’s emissions every year, and evaluatesevaluate compliance 

for the remainder of emissions every three years.89 The EPA 

proposes to evaluate compliance after each multi-year compliance 

period and is not proposing to implement intervening compliance 

 

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

www.rggi.org/docs/ProgramReview/_FinalProgramReviewMaterials/Mod

el_Rule_Summary.pdf Accessed June 9, 2015.

89Overview of ARB Emissions Trading Program. 

www.arb.ca.gov/cc/capandtrade/guidance/cap_trade_overview.pdf 

Accessed June 9, 2015.
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requirements such as those in the RGGI or CARB programs, 

however, the agency requests comment on the inclusion of such 

requirements.

The EPA recognizes that the compliance periods provided for 

in this rulemaking are longer than those historically and 

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

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

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

Guidance on Limiting Potential to Emit in New Source Permitting 

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 
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allowance banking including the banking of Interim-Period 

allowances for use during the Final Period.

Allowance “borrowing” is a type of timing flexibility 

wherein allowances from a future compliance period may be 

“brought forward” and used for compliance in an earlier 

compliance period (thus reducing the amount of allowances 

available for the future period). The EPA notes that the 

proposed multi-year compliance periods inherently provide the 

flexibility to emit at relatively higher amounts in earlier 

years of a given compliance period by using allowances from 

future years within each compliance period (e.g., if the first 

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. 
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The EPA proposes to record allowances in source accounts for one 

compliance period at a time in order to maximize the 

opportunities for a state to replace the federal plan (or 

replace the allowance-distribution provisions of the federal 

plan) with an approved state plan (or approved state allowancedistribution methodology). The EPA proposes to allow a state to 

replace the mass-based trading federal plan (or the federal-plan 

allowance-distribution provisions) with a state plan (or state 

allowance-distribution methodology) for a compliance period for 

which the agency has not yet recorded allowances in source 

accounts. Recording allowances for multiple compliance periods 

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 
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inflation of the allowable emissions at affected EGUs in the 

remaining states subject to the federal plans (to “repay” the 

borrowed allowances). To avoid disruption to sources already 

subject to the mass-based trading federal plan, the EPA is not 

proposing to allow allowance borrowing across compliance 

periods. 

Although not proposing to provide for allowance borrowing

across compliance periods, the agency requests comment on the 

potential inclusion of allowance borrowing in the proposed massbased trading federal plans, including from how far into the 

future to allow allowances to be borrowed, how inclusion of 

borrowing would affect opportunities for states to take over 

implementation of the EGs (or implementation of the allowancedistribution provisions in the mass-based trading federal plan), 

how to address removing the extra allowances from circulation 

that would result if borrowed allowances originate in a state 

that subsequently withdraws from the mass-based trading program, 

and on other complexities that borrowing across compliance 

periods would introduce.

The agency proposes to require sources to demonstrate 

compliance, i.e., allowance true-up, on NovemberMay 1 of the 

year after the last year in the compliance period. For example, 

if the first compliance period comprises the three years 2022, 
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2023, and 2024, then the allowance transfer deadline90 for that

first compliance period (after which point the EPA would 

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

also requests comment on an earlier or later allowance transfer 

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

year in the compliance period. 

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

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

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

Facility-level compliance easesmay ease implementation compared 

to unit-level compliance; each facility has a single compliance 

account in which to hold allowances to cover emissions from all 

its affected EGUs rather than having individual unit-level 

compliance accounts. Fewer accounts makesmay make it easier for 

the designated representatives to manage their allowances. This 

also eliminates the potential for a facility that held 

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

compliance. The EPA has adopted facility-level compliance in 

 

90 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.
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previous emissions budget-trading programs including the Acid 

Rain Program (70 FR 25162), Clean Air Interstate Rule (70 FR 

25162), and Cross-state Air Pollution Rule (76 FR 48208). The 

EPA would continue to track unit-level emissions – while 

evaluating compliance at the facility level – allowing us to 

track increases and decreases of pollutants at individual EGUs.

D. Initial Distribution of Allowances

Establishing a mass-based trading program requires that 

policymakers establish an approach for the initial distribution 

of allowances, historically referred to as “allowance 

allocation.” The EPA believes that states may be well positioned 

to design their own allowance distribution approach because they 

can take into account a wide range of considerations and tailor 

decisions to the particular characteristics and preferences of 

their state. 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. 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-
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distribution approach. The EPA is requesting comment on all of 

these, and any other, approachapproaches to distribute 

allowances.

The initial allowance allocation approach that is based on 

historic data does not affect the environmental results of the 

program or generation patterns; regardless of the manner in 

which allowances are initially distributed, the finite total 

number of allowances limits allowable emissions across all 

affected EGUs. Allowance allocations also are not intended to

prescribe or suggest any unit-level compliance requirements nor

do they limit unit-level operational flexibility, because a 

mass-based trading program provides operators of affected EGUs 

with the flexibility to buy, sell, or bank allowances. Allowance 

allocation is simply a procedure by which allowances are 

distributed into the marketplace so that they may be available 

for affected EGUs to acquire as desired to authorize emissions 

under the program. However, because these allowances are finite 

in number and thus a limited resource, they have value, and as a 

result, initial allowance allocations may raise issues of equity 

among recipients.

Thus the agency recognizes that its choice of allocation 

methodology is important from the perspective of distributional 

effects, and the importance of selecting an approach that is 
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fair and reasonable in light of this consideration and the 

overall purpose of section 111 informs the agency’s thinking in 

this proposal. We also invite comment on these considerations, 

and on any other factors or considerations which commenters

believe should inform the allocation method.

The EPA believes that the most reasonable basis for an 

initial allowance allocation procedure is an approach that uses 

historical data reported by the affected EGUs subject to the 

requirement to hold allowances under this program. This approach

relies on known data rather than future projections. The EPA 

believes this approach is preferable because any approach tied 

to future indicators (e.g., the expected future EGU-level 

pattern of emissions or the ultimate use of allowances) would 

depend on future outcomes that the EPA cannot project with 

perfect certainty in advance. Basing allocation on historic data

is also consistent with the EPA’s approach to initial allowance 

allocation under previously established mass-based trading 

programs.

The EPA proposes to allocate most CO2 emission allowances to 

existing affected EGUs in each state covered by a final massbased trading federal plan, with set-asides for a 

percentageportion of allowances (discussed in more detail 

below). For each compliance period, the agency would distribute 
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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 

three years long, the EPA would aggregate and distribute 

allowances for all three years at the same time. The agency is 

not proposing to allocate allowances to new EGUs, which do not 

have a compliance obligation under this proposed federal plan.

Within each covered state, for each year of the program, the 

agency proposes to allocate &&&98 percent of the allowances to 

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

directly to affected EGUs, the agency proposes to allocate most 

of the allowances using a historic-generation based approach 

and to distribute a percentage (the percentage varies by state, 

as detailed in section V.D.3) using an updating output-based 

allowance set-aside,. As explained below, this proposed updating 

output-based set-aside is intended to prevent or mitigate 

potential emissions leakage to new fossil-fueled units not 

covered by the mass-based plan. The EPA proposes to distribute 

the remaining &&&two percent of allowances to a set-aside pool 

of allowances for renewable energy projects, as described below.

Within each covered state, for each year of the program,

the agency proposes to allocate most of the allowances directly 
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to affected EGUs using a historic-generation based approach. The 

EPA is also proposing three set-asides of allowances, which are 

detailed below.

Although the EPA cannot anticipate the future EGU-level 

pattern of emissions, it is possible to consider potential 

future emission patterns at the source categorysubcategory

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

conducted analysis of emission reduction potential in the two 

affected EGU source categoriessubcategories, i.e., electric 

utility steam generating units (steam generating units) and NGCC 

units. With that analysis as a basis, the EPA is requesting 

comment on an alternative allocation approach that would first 

divide the total number of allowances from each state’s mass 

goal byinto 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 
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proposing that a state may choose to replace the federal-plan 

allowance-distribution provisions with its own allowancedistribution provisions, using any approach to distribute 

allowances that the state chooses, including methods that the 

EPA is not proposing here, provided that the state’s approach 

addresses emissions leakage as detailed in section V.E., and 

includes a Clean Energy Incentive Program as detailed later in 

this section. 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 allowancedistribution provisions with its own allowance-distribution 

provisions is detailed in section V.E.

The following sections discuss and request comment on the 

EPA’s proposed approach to allocate CO2 allowances to affected 

EGUs based on shares of historic generation, the proposed timing 

of allowance recordation, twothree proposed allowance setasides, allocations to units that change status, and the 

proposed approach for states to replace federal-plan allocation

provisions with their own allowance-distribution approaches. In 

addition, we request comment on alternative allowance 

distribution approaches – such as auctioning or allocations to 

load-serving entities – that the EPA or states might adopt. The 
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EPA requests comment on all of these aspects of allowance 

distribution.

1. Proposed Allocation Approach and Alternatives

The EPA proposes to allocate most of the CO2 allowances in 

the mass-based trading program to affected EGUs based on 

historic generation (output) data, while setting. The EPA also 

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

percentageportion of allowances to be allocated 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. The second would set aside a portion of 

allowances in each compliance period except for the first period

(the size of this set-aside would vary by state as detailed in 

section V.D.3); EPA would distribute allowances from this setaside to affected EGUs via an updating output-based set-aside

(the size of the set-aside would vary by state), and setting 

aside twoapproach. 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. In the first compliance yearsummary, the EPA would 

allocate &&&98 percent of allowances using the historic-data 

based approach (i.e., all except two percent for the RE setaside in each state), because the EPA does not propose to 
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proposed set-asides include the output-based set-aside in the 

first compliance period. The EPA proposes to include the outputbased:

(1) Clean Energy Incentive Program. This set-aside starting 

with the second compliance period. The EPA proposes that 

the size (number of allowances) would be of a state’s 

output-based set-aside would remain the same across 

eachfirst compliance period; the allowances only. 

(2) Output-based allocation set-aside. This set-aside share 

would increase relative to the total allowances in a state 

as the mass goals decrease with the steps in the Interim 

Period. The proposed set-asides are detailed in section 

V.D.3.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 
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data) in every state. Further detail on this proposed allocation 

approach is provided in the Allowance Allocation Proposed Rule 

TSD in the docket. The affected-EGU-level allocations resulting 

from this proposed historic-generation-based approach are 

provided in the docket in an appendix to the TSD. The agency 

requests comment on the proposed historic-generation based 

allocation approach and on other allocation approaches.

The EPA proposes to allocate the historic-generation-based 

portion of the allowances (i.e., the mass goal minus the two 

set-asides91) to individual affected EGUs based on each affected 

EGU’s share of the state’s historic generation, using a 2010 

through 2012 data. The calculation steps for this proposed 

historic-generation–based allocation approach are as follows:

1. For each unit in the list of likely affected EGUs in each 

state, identify annual net generation values for the 

historic period of 2010 through 2012 (reflecting affectedEGU-specific generation assumptions incorporated in the 

data adjustments, e.g., assumed capacity factor for “under 

 

91 In the first compliance period this would be the mass goal minus 

the Clean Energy Incentive Program set-aside and the RE setaside. 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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construction” units). For a year for which an affected EGU

has no generation data (e.g., a year before the year when a 

unit started operating), assign the affected EGU a value of 

zero.92 (See step 2, below, for how zero values would be 

treated in the calculations.)

The EPA proposes to use a three-year historic period (i.e.,

2010 through 2012) to reflect unit-level operations over 

time. In the Clean Power Plan EGs, the EPA identified a 

reasonable basis for using aggregate data at the regional 

level largely based on the most recent data year (in that

case, 2012) to inform the establishment of category-wide 

emission guidelinesEGs (as opposed to individual, unitspecific parameters). As a distinct matter, in this context 

the EPA is considering data at the unit level to inform 

unit-specific initial allowance allocations; 

 

92 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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notwithstanding that these allowance allocations do not 

impose any unit-level compliance requirements in and of 

themselves, the EPA finds it reasonable to consider a 

multi-year data period to inform unit-level initial 

allocations in order to consider a broader range of unitspecific 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. 
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3. In each state, sum the average generation values from all 

affected EGUs to obtain that state’s “total average 

historic generation.”

4. Divide each affected EGU’s average generation value by the 

state’s total average historic generation to determine that 

affected EGU’s share of the state’s total average historic

generation.

5. Multiply each affected EGU’s share of the state’s total 

average historic generation by the historic-generationallocation portion of the state’s mass goal (i.e., the 

state’s mass goal minus the set-aside for output-based 

allocations, and minus the set-aside for renewable energy 

projectsasides) to determine that affected EGU’s 

allocation.

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

the mass goal minus only the set-aside for renewable 

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

until the second compliance period.

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

• The agency believes that the proposed historicgeneration-based approach maximizes transparency and 

clarity of allowance allocations. The EPA has placed in 

the docket the historic generation data and the 

calculations used to determine the proposed affected-EGUlevel allocations. The agency also placed the proposed 

affected-EGU-level allocations, resulting from these 

calculations, into the docket. These calculations can be 

relatively easily replicated.

• To calculate allocations, the EPA proposes to use 

historic affected-EGU-level net generation data compiled 

using a methodology similar to the Emissions & Generation 

Resource Integrated Database (eGRID) methodology. The 

proposed calculation approach is described further below 

and in the Allowance Allocation Proposed Rule TSD in the 

docket. The historic-data methodology is described in the 

[&&&reference to Baseline&&&CO2 Emission Performance Rate 

and Goal Computation TSD from final EGs].for CPP Final 

Rule. The majority of the generation-unit-level data in 

this approach are from reports that emissions sources 

submit to the EPA under 40 CFR Part 75 and to the Energy 

Information Administration (EIA) on forms EIA-860 and 
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EIA-923. The EPA believes these are the best data 

available to the agency at the time of this proposed rule 

for calculating affected-EGU-level allocations.

• Allocating based on historic data (as opposed to data not 

yet reported) allows for the distribution of allowances 

prior to the start of the program, which can facilitate

compliance planning.

The proposed approach is transparent, based on reliable 

data, and, like the approaches used in the NOX SIP Call, Acid 

Rain Program, and Cross-State Air Pollution Rule, based on 

historic data. For all these reasons, the agency believes that 

it is appropriate to use 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 
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particular power plant would be the sum of the cost of 

additional fuel to generate an additional MWh, additional 

maintenance costs to increase output by an additional MWh, and 

costs associated with the additional emissions that result from 

generating an additional MWh. In a mass-based trading program, 

additional emissions must be covered by additional allowances, 

so the cost of emitting is the price of the allowances that must 

be consumed to authorize those emissions. These emissionsrelated costs of electricity production are the same regardless 

of whether the allowances used to cover those emissions were 

initially allocated to the user or whether they were acquired 

subsequently in the marketplace.

The same concept applies to any other cost of electricity 

production. For example, a coal-fired electric generating unit 

operator would account for the cost of consuming coal to produce 

generation whether or not the coal was discovered already onsite, 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 
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additional ton. Because a firm loses the opportunity of selling 

an unneeded allowance when it emits an additional ton, even the 

emission of a ton covered by a “free” allowance causes the 

generator to incur the cost of emissions based on the market 

price of allowances the owner must forgo by emitting that ton 

and using that allowance. 

The proposed historic-data based allocation approach would 

not be expected to have any effect on freely competitive 

electricity markets, because the marginal cost of emitting under 

the mass-based trading program is determined by the level of the 

overarching mass goals and is not affected by the distribution 

of the underlying allowances. This marginal cost of emitting is 

what will inform prices, outputs, and competition among power 

plants. While cost-of-service markets are structured differently 

from competitive markets, the regulated utility still makes the 

dispatch decision on the basis of marginal costs among the units 

in its fleet, which is not affected by the amount of allowances 

that any particular unit in that fleet was initially allocated

(assuming a competitive allowance market).

The EPA recognizes that some stakeholders are concerned 

about the potential future distribution of emissions at the 

facility level, and possible effects on communities. However, 

for the reasons discussed in the above paragraphs, allowance 
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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 for discussion of anticipated broad benefits to 

communities.

In addition to the proposed historic-data-based allocations 

approach, the EPA also requests comment on other allocation 

approaches. One alternative approach on which the agency 

requests comment is similar to the proposed approach in that it 

allocates allowances based on historic generation. However, this 

alternative approach would divide the total number of allowances 

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

EGU source categories – based on analysis done in developing the 

source category-specific CO2 emissions performance rates 

promulgated in the Clean Power Plan EGs – before determining 

unit-level allocations. The EPA requests comment on this 

alternative approach because dividing the allowances in a state 

by source category in this manner may result in an initial 

distribution of allowances that would be closer at the sourcecategory level to the future category-level pattern of 

emissions, and thus to allowances ultimately used, than the 
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proposed approach. To the extent that this category-level 

division of allowances is a reasonable proxy for the future 

category-level emissions pattern under the program, this 

approach may reduce wealth transfer between parties that occurs 

as a consequence of a less-anticipatory initial allocation 

procedure. The EPA cannot observe in advance the future 

affected-EGU-level pattern of emissions.

In this alternative approach, for each state the EPA would 

multiply historic steam-generating-unit generation by the steamgenerating-unit source category-specific CO2 emissions 

performance rate, and multiply historic NGCC-unit generation by 

the NGCC-unit source category-specific CO2 emissions performance 

rate. The EPA promulgatedwould do these calculations for each of 

the compliance periods in the Interim Period using the glide 

path interim performance rates, and for the Final Period using 

the final performance rates. These performance rates are shown 

in Tables &&& and &&& in section IV.B, above. The EPA 

established the source category-specific CO2 emissions 

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

section VI in the 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) 
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byinto affected-EGU source categorycategories in proportion to 

the values resulting from the above calculation. The EPA would 

then allocate the steam–generating-unit portion of the 

allowances to individual steam generating 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 historic-generation based 

approach. are

The EPA notes that there are multiple approaches that 

policymakers may use to distribute allowances, beyond the 

proposed or alternative allocation approaches we included in 

this proposed rule. Examples of other allocation approaches 

include allocating based on historic heat input (fuel) or 

historic emissions data, rather than historic generation data.

The choice to use historic data for allocation (e.g.,

generation, heat input, or emissions) means that the

distribution of allowance value will be based on past behavior. 

For example, allocations based on historic emissions would 

benefit those that have historically been the largest emitters, 

whereas allocations based on historic heat input or generation 

(output) would benefit those that have historically used the 
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most fuel or generated the most electricity.93 Alternatively, 

allocations could be distributed based on projected or observed

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

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

approach is reasonable.).

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. The EPA requests comment on the 

use of other updating allocation approaches.

Another allowance allocation approach that could minimize 

the difference between the initial allowance allocation and the 

ultimate distributional pattern of allowance use for compliance 

is to conduct an auction, a process whose express intent is to 

align the allocation of a scarce good (in this case, the limited 

 

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

Trade Program for Pollution Control, EPA, 2003.
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authorization to emit CO2) with the parties most willing to pay 

for its use. Many ascribe benefits, in terms of economic 

efficiency, to the use of auctioning as a means of allocating 

allowances. The EPA notes that some states (e.g., RGGI 

participating states) have used auctions to distribute 

allowances and have used auction revenues for a variety of 

purposes, including the implementation of demand-side energy 

efficiency measures intended to help reduce electricity rate 

impacts and overall program costs, as well as targeted 

investments in overburdenedlow-income communities. The EPA 

believes that if it conducted allowance auctions, any revenue 

from such auctions received by the agency must be deposited in 

the U.S. Treasury under federal law.94 The agency requests 

comment on the idea of auctioning all, or a portion of, each 

state’s allowances in the proposed federal plan, on how much of 

each state’s allowances to auction if not the entire amount, on 

the frequency (e.g., yearly or every few years), design of 

auctions (e.g., spot or advance; first, second-price or other)

and who may participate in the auction.

 

94 The EPA believes authority to conduct auctions is located in 

section 111 alone, as well as by its reference to 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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The EPA requests Onecomment on an alternative approach, 

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

the entities responsible for delivering power to retail 

consumers. LSEs include entities that are investor-owned, 

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

other entities.

Allocation to LSEs can help mitigate bill impacts on 

electricity consumers when applied in concert with certain 

additional design features. In particular, if LSEs commit and/or 

are required to pass through to ratepayers the value from their 

selling of the allocated allowances as condition of receiving an 

allocation of allowances, this approach can mitigate the impact 

of electricity bill increases on consumers that might otherwise 

result from application of the federal plan. As described in the 

Allowance Allocation TSD, this type of approach can also help to 

avoid or mitigate the potential for windfall profits for 

affected EGUs. Economic theory indicates that direct allocation 

to generators could result in profits to generators that, 

despite receiving allowances free of charge, include in the 

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

opportunity cost of having to surrender an allowance (which has 

an economic value) to cover emissions associated with producing 
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that marginal unit of electricity. The EPA could apply this 

approach by conditioning the receipt of allowances by LSEs on 

the pass through to consumers of any allowance value. In 

addition, most LSEs are regulated by state public utility 

commissions that would have authority to ensure that the value 

of allowances directly allocated to LSEs be passed through to 

ratepayers. Other LSEs that are publicly owned or are electric 

cooperatives have governing structures that could ensure that 

allowance value be passed through to ratepayers. if necessary.

The EPA requests comment on the design and utility of 

allocating allowances to LSEs to help mitigate electricity price 

impacts. In particular, the EPA requests comment on options to 

establish conditions requiring pass through of allowance value 

and verification of such pass-through, whether it would be 

appropriate to identify any conditions related to equitable 

distribution of allowance value among ratepayer categories, as 

well as the EPA’s legal authority to apply any such conditions.

Some existing mass-based GHG emission programs allocate 

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

emissions program allocates allowances for free to distribution 

utilities on behalf of electricity ratepayers, with the goal of 
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protecting electricity ratepayers.95 California’s regulations 

stipulate auction proceeds and allowance value obtained by an 

electrical distribution utility from these direct allocations 

“shall be used exclusively for the benefit of retail ratepayers of 

each electrical distribution utility...and may not be used for the 

benefit of entities or persons other than such ratepayers.”96Each 

distribution utility that receives an allowance allocation must 

submit an annual report describing how they complied with this 

provision in their disposition of any auction proceeds and 

allowance value received for the prior calendar year. 

The EPA requests comment on the additional design aspects 

of any potential allocation to LSEs, including but not limited 

to the following questions. : In particular, what metric should 

provide the basis for LSE allocation, e.g.:., electricity demand

served by the LSE, population served by the LSE, emissions

associated with generation serving the LSE, or some other 

metric. If emissions are used as the basis for such allocation, 

what approach should be taken: on a historic basis or a 

continually updated basis, on the basis of estimated emissions 

for the relevant region or some other basis, and using what data 

to calculate such emissions. Finally,Also, EPA requests comment 

 

95 17 CCR § 95892.

96 Id.
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on the form by which LSEs may distribute the allowance value to 

rate-payers, e.g. as a fixed amount, through reduced rates, etc. 

Finally, the EPA requests comment on what share of the total 

number of allowances should be distributed to LSEs and what 

monitoring and reporting requirements may be necessary to 

support an effective program.

The EPA recognizes that allocation to LSEs, by reducing rate 

impacts, could reduce incentives for socially efficient demand 

response, including potential investment in energy efficiency. The 

EPA solicits comment on the magnitude of this effect, relative to 

alternative allocation options, and design options that could help 

mitigate this effect.

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

that divides total allowances from a mass goal byinto source 

categorysubcategories before allocating to individual affected 

EGUs within each source category based on historic generation, 

and on the other alternative approaches described in this 

section. The agency also requests comment on the two proposed 

allowancesallowance set-asides, which are detailed below. The 

agency requests comment on allocation approaches that may 

minimize the impact of this proposed rule on small entities. The 

EPA also requests comment on any other approaches to distribute 
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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 two set-asidesaside allowances – is 

a one-time determination that is not updated. The allocations 

resulting from this approach would be determined prior to the 

start of the program. The EPA proposes to record the historicdata based allowances for each compliance period in source 

accounts prior to the start of each compliance period, and to 

record allowances for one compliance period at a time. Recording 

allowances prior to the start of a compliance period provides 

certainty to affected EGUs of their allocations in advance of 

when the allowances are needed for compliance and can facilitate 

long-term planning. Recording allowances for one compliance 

period at a time provides flexibility for a state to replace the 

federal plan with its own plan in a timely way. As discussed in 

section V.F, 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 
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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.

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 three years long and the first compliance 

period comprises the years 2022, 2023, and 2024, the EPA would 

record allowances for 2022, 2023, and 2024 by June1June 1, 2021. 

The EPA requests comment on the proposed approach of recording 

allowances seven 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

for timing of recordation of allowances from the proposed setasides.

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 
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final guidelines that mass-based plans demonstrate that they 

have addressed the risk of leakage to new unaffected units, as 

specified below.97

The final emission guideline outline concerns regarding 

leakage, which is specified as the risk of increased emissions 

that can be caused when generation shifts over time from affected 

EGUs under the rule to unaffected EGUs (see Sec.VII.C). The final 

guidelines also acknowledge that there are shifts in generation 

across affected sources that could lead to greater or lesser 

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

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

The final guidelines also specify requirements for the 

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

the risk of increased emissions from these generation shifts across 

affected sources.

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

plans, generation may move from existing affected EGUs to new 

sources that are not affected by the final guidelines. This risk 

is not present for existing EGUs under a rate-based plan, because 

CO2 emission performance rates and rate-based goals provide an 

 

97 The EPA is also proposing a third set-aside, for a Clean Energy 

Incentive Program, which is detailed in section V.D.4, below.
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incentive for low-emitting existing sources to maximize their 

utilization, and flexibilities under rate-based plans enable those 

unit to increase utilization by allowing those units to increase 

their emissions under the rate. This characteristic of rate-based 

plans also minimizes the concern of leakage from mass-based 

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

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

be incented to maximize their utilization, and thus will not have 

as much opportunity to increase their output to replace generation 

from existing units in mass-based states. But new units in ratebased and mass-based states are more likely to have the opportunity 

to increase their utilization in order to replace generation from 

mass-based existing sources, and the mass-based affected EGUs

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

have the opportunity to increase their emissions in the same way

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

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

to assure equivalency between CO2 emission performance rates (as 

well as rate-based goals) and mass-based goals.

The final guidelines require that jurisdictions 

implementing a mass-based option make a demonstration that 

leakage has been addressed in their plan (See Sec.VIII.L). The 

options for making that demonstration includeThe final emission 
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guidelines, in Sec.VII.D, specify leakage to be 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.98 This 

section of the final guidelines also specifies how leakage must 

be addressed as part of an implementation of a mass-based goal 

as an expression of BSER. This is because a mass-based approach 

provides differing incentives to existing affected EGUs and new 

unaffected sources, unlike under a rate-based approach. This 

provides an increased potential for leakage under a mass-based 

approach, and thus states adopting mass-based plans must address 

leakage in order to assure the mass-based goal is equivalent to 

the mathematical expression of BSER in CO2 emission performance 

rates. 

Therefore, the final guidelines require that jurisdictions 

implementing a mass-based plan approach make a demonstration 

that leakage has been addressed in their plan (See final 

guidelines Sec. VIII.J). The options for making that 

demonstration include: creating a mass limit that opts in new 

 

98 Section VII.D of the final guidelines is incorporated by 

reference in this proposal.
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sources, implementing allocation strategies that address 

leakage, or justifyjustifying why leakage is not a concern for 

the jurisdiction because of existing policy or unique 

characteristics. We are proposing under the federal plan and 

model rule to address leakage through the use of allocations 

strategies, specifically through the use of a combination of an 

output-based allocation set-aside and a set-aside that 

encourages the installation of RE. In the section below, the 

EPA discusses why we have chosenIf a state were to adopt 

allowance set-aside allocation strategiesprovisions exactly as 

the approach to address leakage. they are outlined in the 

finalized model rule, they could be considered presumptively 

approvable.

Sec. VIII.J of the final guidelines provides a discussion 

of how set-asides can effectively address leakage in a massbased plan approach, and that section in incorporated by 

reference in this section of the federal plan and model rule 

proposal. That section of the final guidelines 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 fuelfired EGUs. This is because the EPA does not have authority to 

extend regulation of and federal enforceability to new fossil 
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fuel-fired sources under CAA section 111(d), and therefore we 

cannot include new sources under a federal mass-based plan 

approach.

Set-asides can also be used to target and refine allowance 

allocation in order to achieve beneficial outcomes, for example 

ensuring program integrity and mitigating costs. The set-asides 

we are proposing – described in detail below - would establish a 

pool of allowances that would be allocated to affected EGUS or 

other entities, and would be allocated based upon different 

criteria in order to support particular program goals., in 

particular addressing leakage.

These set-asides are essentially a type of “economic 

incentive” authorized by the CAA as a means of pollution 

prevention and control, and the expected benefits of this 

particular type of economic incentive to address leakage make it

appropriate here.99 The EPA believes these set-aside programs are 

both authorized and consistent with the purpose of the Clean 

Power Plan under section 111(d) and the specific requirements 

 

99 In designing a federal plan under section 111(d), the EPA 

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

available under 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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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 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 section 110 of the Clean Air Act. For 

example, in the Cross State Air Pollution Rule (CSAPR), the EPA 

used a 5 percent set-aside for new units, because we believed it 

was “important to have a small new unit set-aside in each state 

to cover new units within the budget that was set aside in order 

to address the state’s significant contribution and interference 

with maintenance.” (75 FR 45310; Aug. 2, 2010). This was 

important, in the EPA’s view, because it allowed for growth in 

the electric utility sector consistent with the EPA’s modeling, 

where new units showed up in the modeling output as surrogate 

facilities representing potential new EGUs that come online in 

future years in response to demand increases or other market 
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drivers.100 As between a choice of requiring these new units to 

purchase their allowance on the open market, versus being 

treated in the same manner as existing – and generally 

understood to be less efficient and more polluting – units, 

i.e., by being eligible to receive a free allocation out of the 

new unit set-aside, 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 

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 

 

100 See also EPA, Allowance Allocation Final Rule TSD, EPA-HQ-OAR2009-0491, at 3-4 (June 2011).
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utilities are looking for opportunities everywhere.”101 The 

reserve program was nonetheless undersubscribed, and the EPA and 

other parties have learned from this case and made adjustments 

to similar programs to promote participation. This can be done 

through using alternate strategies for the MWh-to-allowance 

ratio, such as the pro rata distribution strategy proposed as 

part of the RE set-aside. This proposal also tries to minimize 

the administrative burden associated with participation in the 

set-aside.

In the NOX SIP Call, the EPA encouraged states to “consider 

including energy efficiency and renewables as a strategy in 

meeting their [emission] budgets. One way to achieve this goal 

is including a provision with a state’s NOx Budget Trading Rule 

that allocates a portion of a state’s trading program budget to 

implementers of energy efficiency and renewable energy projects 

that reduce energy-related NOx emissions during the ozone 

season.” See 63 FR 57356, 57438 (Oct. 27, 1998). A number of 

states created RE and demand-side EE set-asides in their SIPs in 

response, and later, for the implementation of CAIR. A 

“roundtable” meeting with 25 states in 2006 indicated that 

states that had established these programs were generally having 

 

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

Reserve, EPA 430-R-94-010 (Nov. 1994).
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success with them, and provided a forum for exchanges of ideas 

on how to handle a variety of implementation issues, such as 

over- and under-subscription, application issues, compliance and 

verification, the appropriate size of a set-aside account, how 

to garner public input on which projects are selected, and other 

issues.102 In general, the EPA believes its experience and those 

of the states with these set-aside programs support the view 

that they are an effective means to spur clean energy projects, 

which in turn we believe can help to reduce the risk of leakage 

in this instance.103

 

102 U.S. EPA, State Clean Energy-Environment Technical Forum 

Roundtable on State NOx Allowance EE/RE Set Aside Programs, Call 

Summary (June 6, 2006), available at 

www.epa.gov/statelocalclimate/documents/pdf/summary_paper_nox_al

lowance_6-6-2006.pdf. 

103 The agency has extensive experience in the design and 

establishment of set-aside programs. See, e.g., Guidance on 

Establishing an Energy Efficiency and Renewable Energy (EE/RE) 

Set-Aside in the NOx Budget Trading Program (March 1999), available 

at 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 

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 
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Below, the EPA describes two potential allowance setasides. First, the EPA proposes a set-aside for allowances 

distributed to existing NGCC units based on output (i.e.,

output-based allocation) to mitigate emission leakage to new 

sources, with the ancillary advantage of further addressing the 

potential for the risk of increased emissions due to movement of 

generation to existing sources in neighboring states that adopt 

rate-based approaches, though the risk ofpotential for that that 

is minimized by the incentives present under a rate-based plan. 

Second, the EPA proposes a set-aside for electricity generation 

from qualifying renewables. This set-aside also addresses the 

potential for leakage to new sources, as increased RE capacity 

can serve electricity demand in place of new sources. The EPA 

also solicits comment on other set-aside options that could 

support the goals of the program., in particular addressing 

leakage, including a set-aside that provides an incentive for 

demand-side EE. The EPA seeks comment on all aspects of the setaside options specified in this section. This includes the 

inclusion of a set-aside, the method for allocation of 

allowances to set-asides, the size of the set-asides, the 

 

Energy Efficiency and Renewable Energy Actions (July 2007), 

available at www.epa.gov/statelocalclimate/documents/pdf/eere_set-asides_vol3.pdf.
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requirements for the process of distribution, eligibility 

requirements for receiving set-aside allowances, the proposed 

process for redistribution of undistributed allowances from each 

set-aside, and any other appropriate set-asides.

a. Set-asides for Output-based Allocation

The EPA is proposing a set-aside approach referred to as 

output-based allocation, which provides targeted allocations of 

a limited portion of allowances to existing NGCC units as a 

means of mitigating emissions leakage to new units or existing 

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

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

environmental integrity of a mass-based plan, and could 

potentially reduce costs, and as well as address incentives for 

generation to shift away from EGUs covered under mass-based 

plans to new unaffected EGUs. We seek comment on all aspects of 

this proposal and its underlying rationale.

Under the output-based allocation approach we are 

proposing, some of the total allowances within each mass-based 

state are allocated to existing NGCC units based, in part, on 

their level of electricity generation in a recent period. The 

allocation to an eligible EGU is not fixed, but instead 

dependdepends on its generation. Each eligible EGU maywould get 

a larger allowance allocation if it generates more such that 
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owner/operators of eligible EGUs will have an incentive to 

generate more in order to receive more allowances, making them 

more competitive than they would be without the set-aside. 

Because the total number of allowances is limited, this 

allocation approach will not exceed the overall emission goal; 

instead, it merely modifies the distribution of allowances in a 

manner designed to mitigate emission leakage.

Output-based allocation provides an incentive for eligible

EGUs in mass-based states to increase their generation in order

to increase their allocation of allowances. This incentive helps 

align the generation incentives for eligible EGUs in mass-based 

states with new EGUs within mass-based states that are not 

subject to the mass-based limits as well as analogous EGUs in 

other states covered by emission rate limits, mitigating

emissions leakage. The EPA also solicits comment on another 

potential ancillary benefit of this set-aside: mitigating

electricity price impacts associated with the proposed federal 

plan. Output-based allocation lowers the marginal production 

cost of eligible EGUs. Therefore, if these EGUs influence 

electricity prices, the reduction in their production costs will 

place downward pressure on the electricity price. In the 

specific situation where eligible EGUs are in cost-of-service 

regions, the effect on electricity prices would depend on the 
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relative cost of producing electricity from these EGUs relative 

to the cost of procuring power from EGUs subject to emission 

rate standards. 

It is important that the output-based allocation approach 

be designed to avoid unintended consequences. In particular, the

design should reflectavoid, to the fact that its application may 

reduce theextent possible, reduction in incentives to invest in 

new zero- or low-emitting generation as a result of the downward 

pressure itthe allocation approach may place on electricity 

prices. This is also why an RE set-aside is a useful complement 

to the output-based allocation set-aside.

Furthermore, providing too strong a generation incentive to

affected EGUs eligible for the set-aside could increase total 

electricity production costs. Specifically, if applied too 

strongly, output-based allocation can go beyond the alignment of 

incentives across similar EGUs and lead to undesirable 

differences in incentives in the other direction. For example, 

if eligible affected EGUs receive too a large a number of 

allowances for each MWh of generation this could incentivize

generation that is high cost, exclusive of the cost associated 

with obtaining the mass-based emission limit, and disincentivize

lower-cost generation subject to emission rate standards. This 

could raise the total cost of achieving overall emission levels
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with relatively little environmental benefit. The output-based 

allocation set-aside should be designed to address these

economic concerns. 

The EPA accordingly solicits comment on key parameters for 

the appropriate design of the output-based allocation approach 

used for this proposed set-aside. Key parameters to be 

identified under the output-based allocation approach include 

which affected EGUs receive the allocation, the vintage for 

allowances, the allocation rate(s), and the size of the setaside. The EPA solicits comment on what other key 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, subject to limitations described below. The EPA 

recognizes that performance of output-based allocation may be 

improved by targeting which units receive this additional 

incentive. In particular, this approach can most effectively 

address emission leakage if targeted to those affected EGUs that 

face the greatest difference in their incentive to generate 

relative to otherwise similar EGUs subject to emission rate 

standards. As noted in the discussion of the allocation rate 
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below, new combustion turbines would be expected to generate 

more absent this set-aside. Therefore, the difference in 

generation incentives between affected stationary combustion 

turbines under mass-based implementation and otherwise similar 

new stationary combustion turbines subject to the 111(b) 

standards is likely one of the most salient deviations in 

production incentives to address.

As discussed further below, under this proposal other 

affected EGUs, and EGUs not subject to the emissions guidelines,

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

Below we also takerequest comment on whether sources other than 

combustion turbines sourcesNGCC units subject to the emissions 

guidelines should be eligible for output-based allocations under 

this set-aside. 

The EPA also proposes that this approach be targeted 

towards marginal generation by providing allocations under this 

set-aside only to eligible EGUs that exceed a certain average 

capacity factor over the compliance period, and only for the 

portion of their generation that exceeds the specified capacity 

factor. The allocation rate would only apply above a particular 

average capacity factor because it is intended to incentivize 

marginal generation and not generation that would have otherwise 

occurred absent the output-based allocation from the set-aside. 
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Under this approach, eligible affected EGUs would receive no 

allowances from this set-aside for generation below this average 

capacity factor (although all affected EGUs will still receive 

allowances through the default allocationhistoric-generationbased approach and any applicable set-asidedetailed above). This 

approach avoids incentivizing production at lower levels of 

generation from an eligible source, and therefore avoids 

discouraging a relatively inefficient or infrequently used EGU 

from retiring.104 The EPA proposes an approach under which each 

existing NGCC that each EGUis eligible for the set-aside receive

output-based allocation at the allocation rate only if its 

average capacity factor in the compliance period is above 50

percent on a net-basis [&&& check net].. Furthermore, we propose 

that each eligible EGU receives allowances at the allocation 

rate for all generation above an average capacity factor of 50

percent. That is, there would be no “maximum” average capacity 

 

104 As discussed below, if a source would no longer receive 

allowance allocations after it retires it would be discouraged 

from retiring, which may increase total production costs. The logic 

for not providing output-based allocations to sources with low 

capacity-factors is the same, although the strength of the 

incentive to not retire is lower for output-based allocation than 

it is when the entire allocation to the source may be forfeit 

through retirement.
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factor above which output-based allocations are not earned by an 

EGU eligible to receive them.105 This is to maintain the marginal 

incentive to generate from the affected EGU. (The total number 

of allowances available in the set-aside is limited, however, as 

described below.) The EPA requests comment on implications of 

this approach for the operation and efficiency of electricity 

markets.

Next, The EPA also solicits comment on selection of a

source of allowances that is a specific vintage for allocation. 

This key parameter determines which compliance period’s 

allocation is distributed based, in part, on current period 

generation. Alternatives include the current compliance period’s 

allocation, which is the period in which the eligible generation 

occurs, and a future compliance period’s allocation. If 

allowances are allocated from a future period’s allocation, 

affected EGUs can receive additional allowances in a given 

future period, based on their additional generation in the 

current compliance period.

Both approaches create an incentive to increase generation 

in the current compliance period to secure additional 

allowances; the difference is in when those allowances may be 

 

105 Effectively, the allocation rate of output-based allocation is 

zero up until this average capacity factor. 
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used. Allocating current compliance period allowances based on 

current year generation may create uncertainty in that affected 

EGUs may not know if they will be allocated sufficient 

allowances to cover their emissions or will have to buy 

allowances, because their total allocation will not be fixed 

until the end of the period when their cumulative generation is 

known. Therefore, an advantage of allocating allowances from a 

future compliance period is that affected EGUs will know ex-ante 

how many allowances they will be allocated in a given period. 

However, if there is an expectation that the federal plan will 

be replaced by a state plan in the future compliance period, the 

incentive to respond to output-based allocations is potentially 

diminished. The longer the lag between the eligible generation 

and the output-based allocation, the greater the potential for 

uncertainty to lower the incentive associated with output-based 

allocation. At the same time, the ultimate effect of outputbased allocation timing will also depend on expectations about 

future allowance prices relative to current prices and the 

degree to which the banking of allowances is permitted. 

Weighing these observations, the EPA specifically proposes

allocating allowances based on generation from eligible EGUs in 

the preceding compliance period. For example, the EPA would 

calculate set-aside allowances for the second compliance period 
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(2025 through 2027) based on data from 2022 through 2024. In the 

first compliance period of the federal plan, allowances 

allocated to affected EGUs would be distributed per the 

historic-generation-based approach described above (with no 

further adjustment). The EPA also requests comment on other 

approaches to selecting a vintage (or vintages) for allocating 

allowances for an output-based allocation set-aside.

Further, we requestThe EPA requests comment on options for 

the allocation rate under this approach. The allocation rate is 

the emissions-equivalent number of allowances that the affected 

EGU receives per one net MWh of generation eligible for the setaside. In particular, we request comment on settingThe EPA

proposes to set the allocation rate equal to the emission rate 

standard (on a net-basis) for new stationary combustion 

turbinesNGCC units under 111(b), in order to align the 

generation incentives across EGUs eligible for the set-aside and 

the type of new emitting source that would generate more absent 

this set-aside [&&&REF].(&&&cite to 111(b) rule). Specifically, 

an additional MWh of eligible generation would earn the affected 

EGU allowances equal to the level of emissions permitted per MWh 

of net generation under the 111(b) new source standard, which is 

&&&___lb/MWh-net.1,030 lb/MWh-net. The EPA requests comments on 

other values for the allocation rate (or, potentially,
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allocation rates). 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 uniform rates under the Clean Power Plan EGs (see 

section VI in the EGs).

The EPA proposes to calculate allocations to NGCC units from 

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

compliance period. For example, the EPA would calculate set-aside 

allowances for the second compliance period (2025 through 2027) 

based on data from 2022 through 2024. Each NGCC-unit affected EGU

with an average capacity factor above 50 percent in the preceding 

compliance period would earn set-aside allowances. 

The EPA proposes to calculate an NGCC unit’s capacity 

factor based on the previous compliance period’s net generation 

and the net summer capacity of the unit. The EPA is proposing to 

require affected EGUs to report net generation to the agency 

(see section V.H for proposed monitoring and reporting 

requirements).106 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; 

 

106 The EPA proposes to make the reported generation data available 

to the public on the agency’s website.
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we would add EGU-level net summer capacity as a required data 

field in the certificate of registration that a unit’s owner/ or 

operator would submit to the agency per the procedure detailed 

in section V.G. The EPA requests comment on the relative 

efficiency of obtaining net summer capacity from data reported 

to EIA or of adding net summer capacity as a required data field 

on the certificate of registration. The EPA notes that the EIA 

net summer capacity data is reported at the generator level not 

the affected-EGU level; if we add this data point to the 

certificate of registration it would be reported at the 

affected-EGU level, which would facilitate calculation of the 

capacity factors. The EPA also requests comment on whether the 

“maximum load value,” which is a parameter that EGUs report to 

the EPA in their monitoring plans, is a reasonable proxy for 

EGU-level net summer capacity for these calculations. The EPA 

also requests comment on an alternative approach of basing the 

capacity-factor calculation on nameplate capacity instead of net 

summer capacity, or other approaches to the calculation.

After identifying NGCC units with average capacity factor 

above 50 percent, the EPA would then calculate the amount of 

allowances these affected EGUs would receive from the outputbased set-aside as the unit’s net generation above an average 

capacity factor of 50 percent in the preceding compliance 
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period, multiplied by the 111(b) rate standard for NGCC units of 

&&&__1,030 lb/MWh-net. (The proposed approach to determine the 

size of the set-aside is detailed below.)

The EPA proposes to provide notice of the capacity and 

generation data used to calculate allocations from the setaside, and the resulting allocations, by August 1 of the first 

year in each compliance period, e.g., by August 1, 2025 for the 

compliance period that commences in 2025. (and based on the data 

from the prior compliance period). The agency proposes to 

provide 30 days for comment on the data and allocations, until 

August 31, and to provide notice of the final set-aside 

allocations by November 1 of the same year and record the 

allocations in the source accounts at that time. The EPA 

requests comment on other approaches to providing notice of the 

data and allocations.

The EPA requests comment on all aspects of the proposed 

approach to calculate output-based set-aside allocations. 

Further details of the proposed approach are in the Allowance 

Allocation Proposed Rule TSD in the docket.

The EPA proposes a particular to determine the size of the 

set-aside that is based on the total allocationallowances in 

each state, the allocation rate, the capacity factor above which 

eligible generation may receive the output-based allocations, 
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and an average capacity factor across all sources potentially 

eligible for allowances from the set-aside. In particular, the

EPA proposes that the share of the total used for the set-aside

be equal to the allocation rate, (i.e., 1,030 lb/MWh-net),

multiplied by the amount of potential generation from all NGCCunit affected EGUs eligible for the set aside in the state above 

an average capacity factor of 50 percent and below an average

capacity factor of 7060 percent, based on 20142012 data as 

detailed below. The 50 percent average capacity factor is the 

capacity factor above which eligible generation may receive the 

output-based allocations. The 7060 percent capacity factor 

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

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

section V.D.1].(as detailed above). Maintaining a relatively

large share of allowances allocated based on historic generation 

provides all EGUs subject to the mass-based plan certainty in 

their allowance allocation. Furthermore, limiting the size of 

the set-aside avoids the risk of incentivizing too much 

generation from eligible sources.

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

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

EIA for the year 2014.from the Clean Power Plan EGs (&&&cite to 

EGs baseline TSD). The EPA would calculate the size of the set-
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aside as the sum of net generation from NGCC-unit affected EGUs

that operated above 5010 percent and below 70 percentof the NGCC

capacity factor in 2014the state107 multiplied by the 111(b)hours 

in a year (8,760 hours) multiplied by the allocation rate 

standard for NGCC units of &&&___the set-aside (1,030 lb/MWhnet.)..

The set-asides resulting from this proposed approach are 

shown in Table &&&. The set-asides in the table would apply to 

every compliance period except for the first compliance period 

for which there would be no output-based set-aside. Although the 

size of the set-aside would remain the same for each compliance 

period, as the mass goals decrease with each step in the Interim

Period and to the Final Period, the set-asides would constitute 

an increasing share of a state’s mass goal. The Allowance 

Allocation Proposed Rule TSD further details the proposed 

approach to determine the size of the set-aside. The EPA 

requests comment on a potential limit for the size of the setaside in a compliance period based on a percentage of the 

state’s total allowances for the compliance period.

 

107 The sum of net summer capacity for affected NGCC units in the 

2012 baseline for the Clean Power Plan EGs (&&&cite to EGs baseline 

TSD).
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Table &&&. Proposed Size of Output-based Set-aside for the 

Second Compliance Period and Later

(MetricShort Tons)

State Allowances in outputbased set-aside

Alabama 4,176,474

Arizona 4,197,813

Arkansas 2,102,538

California 8,434,153

Colorado 1,314,351

Connecticut 1,090,811

Delaware 649,190

Florida 12,091,409

Georgia 3,589,270

Idaho 246,638

Illinois 1,341,194

Indiana 1,106,150

Iowa 502,344

Kansas 62,257

Kentucky 288,730

Lands of the Fort Mojave Tribe 248,127

Lands of the Navajo Nation 0

Lands of the Uintah and Ouray Reservation 0

Louisiana 2,207,879

Maine 563,925

Maryland 103,762

Massachusetts 2,436,833

Michigan 2,110,658

Minnesota 909,724

Mississippi 3,400,197

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 3,817,411
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North Carolina 2,120,178

North Dakota 0

Ohio 1,757,326

Oklahoma 3,153,604

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 15,998,146

Utah 825,586

Virginia 3,025,345

Washington 1,383,060

West Virginia 0

Wisconsin 1,181,175

Wyoming 45,114

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

set-aside once, before the start of the program, and not to

change the size. The EPA also requests comment on updating the 

size of the set-aside once after the start of the Final Period 

using data from 2030 or another year, and also seeks comment on 

updating the size of the set-aside more than once after 2030, 

for example every six or eight years. If the EPA updated the 

size of the set-aside, we would provide notice of the data upon 

which we intended to rely and opportunity for comment; the EPA 

requests comment on this approach. 

Given the proposed limit on the total size of the setaside, and the amount of potential generation eligible for the 

set aside, there may be fewer allowances available in the set 
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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. 

We proposeThe EPA proposes that if the number of allowances 

allocated from the set aside is less than the size of this setaside, then the remaining allowances would be distributed to all 

affected EGUs using the historic-generation based-approach 

described above.

The EPA also requests comment on extending output-based 

allocation from this set aside to affected utility boiler. 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 utilitysteam generating 

units would incentivize generation from relatively high-emitting 

EGUs, thereby leading to highwhich would likely increase

allowance prices, which then counteracts as other emission 

reductions are made to respect the overarching mass limit. This 

approach would thus counteract the intended effect of lowering 
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the cost of production ofcost 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 solicits comment on the general merits of the 

proposed set-aside and the output-based allocation used under

this set-aside. In addition, the agency solicits comment on how 

such an approach could be targeted to improve implementation of 

the proposed mass-based trading federal plans and improve 

overall environmental and economic performance. In particular, 

the EPA solicits comment on which affected EGUs or other 

generation sources should receive any output-based allocation, 

the proper allocation rate(s), the total size of the set-aside, 

and from which compliance period’s total allowances the setaside should be drawn. 

b. Set-asides for Renewable Energy Projects 

The EPA proposes to provide a set-aside of allowances for 

distribution to renewable energy (RE) in each state covered by 

the proposed mass-based federal plan as part of the mass-based 

trading program,, if it is finalized. The agency is also taking 

comment on whether distribution should extend to demand-side 

energy efficiency (DS-EE) and combined heat and power (CHP) 
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projects. Under this program, the EPA would reserve a percentage 

of each state’s allowances (i.e., a percentage of its mass) in a 

set-aside account for each state. Developers of RE projects 

could apply to receive set-aside allowances based on the 

projected generation from eligible RE capacity. 

Such a program will serve to facilitate source compliance 

with the emission guidelines.EGs. First, the set-aside maywill

address leakage concerns regarding leakage by lowering the 

marginal cost of production of the incented clean energy 

technologies within the state. This will make RE more 

competitive against new sources, reducing the potential for 

leakage to new sources. 

All else being equal, this also lowers the cost of 

generation in the state overall, and thus can avoid leakage of 

generation to another state. By lowering the cost of generation,

it may also lower its price for electrical consumers, depending 

on how much the increased cost of allowance for affected EGUs is 

reflected in electricity costs. While the proposed set-asides 

would provide additional incentive for the creation of 

additional RE capacity, it should also be noted that the 

proposed mass-based trading program itself would provide 

incentive for new and existing low and zero-emitting generation.

The EPA is aware of at least one existing program that 
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supports deployment of RE and demand-side EE using the proceeds 

from the auction of tradable CO2 allowances – the Regional 

Greenhouse Gas Initiative (RGGI). RGGI adopted an allocation 

approach in which states could invest auction proceeds to 

support DS-EE and RE deployment programs. It was recognized that 

such investment is a means to reduce the potential for emission 

leakage from a carbon cap-and-trade system in the United States

(in RGGI’s case, to sources located outside the RGGI states). As 

will likely be similar to the proposed federal plan here, RGGI 

only covers a subset of states. TheA RGGI staff proposal in 2008

recognized that reduced electricity demand can reduce the 

potential for emissions leakage of generation from a 

participating to a non-participating state, by reducing the 

demand for fossil fuel-fired electric generation, which in turn 

reduces the demand for CO2 allowances, and thus reduces allowance 

prices within the RGGI market.108 Under the RGGI program, more 

than 90 percent of CO2 allowances are distributed through 

auction, and more than 60 percent of cumulative investment of 

auction proceeds has been directed to DS-EE.109 While not a set-

 

108 RGGI, Potential Emissions Leakage and the Regional Greenhouse 

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

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

109 RGGI, “Second Control Period CO2 Allowance Allocation,” March 
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aside program per se, the basic concept is similar in that RGGI 

uses the proceeds from the auction of emission allowances to 

fund programs for DS-EE and RE that are both complementary with 

the overall purpose of the program (to reduce CO2 emissions), and 

which also assist in ameliorating the leakage concern.

The 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 

 

25, 2015. Available at 

www.rggi.org/docs/CO2AuctionsTrackingOffsets/Allocation/SCP_Allo

wance-Allocation.pdf. RGGI, Investment of RGGI Proceeds through 

2013, April 2015. Available at 

www.rggi.org/docs/ProceedsReport/Investment-RGGI-ProceedsThrough-2013.pdf.
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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 Allocations TSD. We 

note that, under the proposed framework, these allowances would 

be available to affected EGUs either in the marketplace or 

through subsequent distribution of unclaimed set-aside 

allowances, and thus the provision of these set-asides does not 

affect the overall stringency of the program.

In Sec. &&&V.D.4,&&&, the EPA is proposing that the size of 

the RE set-asides may grow over time as certain units shift out 

of the program.

It is the agency’s intention that states electing to 

submit a state allowance-distribution methodology under the 

federal plan will have the flexibility to determine their 

allowance-distribution method, and thus may determine whether to 

include a set-aside and how such a set-aside will be distributed 

if they choose to submit a state allowance-distribution 

methodology. The allowance distribution methodology must still 

contain an allocation strategy to address leakage, unless the 

jurisdiction can make the justification that leakage is already 

addressed by existing policy or, by unique characteristics of 

the jurisdiction or by some other aspect of their state plan.
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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 this proposal Sec. &&& andIV.Cand the final 

guidelines Sec. VIII.&&&..K. 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 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 assures 

that the entities eligible to receive set-aside allowances are 

those 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 

proposes that the actions resultinggeneration for which an 

entity receives allowances from the set-aside would not be 

eligible to be counted as creditsfor ERC issuance in rate-based 

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

is proposing that the same RE measures are eligible to receive 

set-aside allowances under a mass-based federal plan as would be 

eligible for ERC issuance under a rate-based federal plan. 

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 Sec.IV.F.2 above. AllNew 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.F.2 C of this preamble and the requests for comment 

included within that section also apply in the mass-based setaside context. For example, we are requesting comment on the 

inclusion of other RE measures, incremental nuclear, demand-side 

EE measures, CHP and any other technologies as eligible measures 

to receive set-aside allowances. We particularly request comment 
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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 projectionbased 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 

Sec. IV.F.2 in a mass-based set-aside context. We also request 

comment on possible avenues to add new technologies to this 

specified set of measures 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 

question, and a projection of expected annual megawatt-hour 

generation for an RE project. The EPA must approve the 
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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 may be deposited.In addition, the proponent must 

register for a general account in the EPA tracking system where 

the allowances would be recorded. See section 62.16320 for the 

requirements to establish a general account. While EPA is 

proposing to allow eligible resources to use a general account 

to receive any allowances allocated under this section, EPA 

requests comment on extending the designated representative 

provisions in section 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 section 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 
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is based upon projections provided prior to generation rather 

metered data provided after the generation occurs. (though we 

are proposing that the projections will be checked against expost metered data). The projection method enables the 

distribution of set-aside allowances prior to the relevant 

compliance year whileduring which the generation occurs. The EPA 

feels this still provides sufficient rigor because the set-aside 

does not affectingdirectly affect program stringency. The reason 

that stringency is not affected is because of key differences 

between issuance of credits and distribution of set-aside 

allowances. Under rate-based implementation, each decision to 

recognize issue an ERC based on a quantification of RE with 

ERCsgeneration affects the ultimate amount of allowable CO2

emissions;, because the number of ERCs is determined by the 

amount of MWhs approved as eligible for ERC issuance. 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 CO2 emissions 
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outcome because the ultimate amount of allowable CO2 emissions is 

determined by the total number of allowances initially created 

(regardless of how they are distributed). As a result, while the 

EPA believes it is reasonable to consider a minimum set of 

qualifications for recognizing RE through these allowance setasides to assure that the RE generation that is incented is 

actually produced, the EPA does not believe the overall 

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 based on actual MWhmegawatt-hours

provided by the installation in a prior year or compliance 

period, or another form of historical generation data.

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 compliance year in 

question.year during which the RE generation occurs (the 

“generation year”). The EPA or its agent will review and approve 

the project as eligible and it will be entered into the pool of 

projects that will receive set-asides in any compliance period. 
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If approved, the number of projected megawatt-hours in each 

compliancegeneration year will be the basis of the number of 

allowances the provider will receive, as an input to the 

methodology specified below. The providers will have an 

opportunity to update projections for future 

compliancegeneration years, these projections must be received 

by June 1 of the year prior to the compliancegeneration year in 

question. 

On December 1 of the year prior to each year of the 

compliance period in question, the EPA is proposing to 

distribute allowances from the set-aside to approved providers. 

The agency is proposing to distribute set-aside allowances to 

approved RE providers pro-rata, with the number of allowances 

distributed to each provider according to the percentage of 

total approved RE MWHsmegawatt-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 compliancegeneration year, RE providers 

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

megawatt-hours 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 reports. 

If the project or program does not reach the megawatt-hours 

projected in a particular compliancegeneration year, the 

unfulfilled megawatt-hours will be subtracted from that RE 

provider’s MWhsmegawatt-hours eligible for the set-aside in the 

next compliancegeneration year, or multiple years if the deficit 

exceeds the MWhs projected for the upcoming year. If this 

deficit is greater than 10% percent in a particular year, the 

provider will need to provide an explanation of the deficit and 

will be required to reevaluate their projections for future 

years. If such deficits continue through all three years of the 

any complianceperformance period in which they participate, the 

provider will be disqualified from receiving future set-asides 
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for the following compliance period.. We also take comment on 

whether a provider with continuing deficits should also be 

disqualified from receiving ERCs for some or all of the 

remaining performance periods. The agency requests comment on 

all of the specified aspects of this distribution process.

The EPA is proposing that once allowances have been 

distributed to all approved providers, any remaining allowances 

in the set-aside, such as set-aside allowances designated for 

projects that no longer exist, will be redistributed to affected 

EGUs in the state in a pro rata fashion on the same distribution 

basis as their initial allocations were made. It is proposed 

that this will occur immediately after the distribution of setaside allowances to eligible RE providers on December 1 of the 

year prior to the compliancegeneration year in question. The EPA 

requests comment on this approach.

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 d 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

&&&Placeholder while this section is being worked on 

offline&&&

4.5. 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, starting 

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

be allocated to the renewable energy set-aside for the state in 
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which the retired unit is located.110 In other words, the retired 

unit would continue to receive allocations for four years after 

it ceases operation. Continuing allocations to non-operating 

units for a period of time reduces the incentive to keep a unit 

operating simply to avoid losing the allowance allocations for 

that unit (e.g., a unit that would otherwise be retired due to 

age and inefficiency). On the other hand, non-operating units 

are no longer emitting and so do not need allowances. The EPA 

believes that the proposed approach of allocating allowances for 

a specified, but limited, period after a unit ceases operating

is a reasonable middle ground approach. The proposed approach 

also allows the renewable energy set-asides to grow over time.

The agency requests comment on this approach.

The EPA proposes to record allowances for each year of a 

multi-year compliance period at once, seven 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 

 

110 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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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 three-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 three years of non-operation.

As a further example, if an affected EGU does not operate for 

both calendar years of a two-year compliance period, then 

starting with the 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 four 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 
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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.

The EPA also requests comment on approaches that might 

consider extending the period for which a retired unit continues 

to receive allocations to address (&&&).

Units that are modified or reconstructed. Similar to the 

approach for an affected EGU that retires, the EPA proposes that, 

if an affected EGUa unit is modified or reconstructed such that it 

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

plan, then starting with the next compliance period for which 

allowances have not yet been recorded, the allowances that would 

otherwise have been allocated to that unit, starting in the first 

year after the year the unit is modified or reconstructed, the 

unit would be allocated to the renewable energy set-aside for the 

state in which the unit is located [&&&will confirm . The EPA 

requests comment on this language based on final decision on 

treatmentproposed approach, including on the number of 

modified/reconstructed units in EGs]. 

The EPAyears for which a unit would continue to receive 
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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 

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 
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flexibility in its allowance distribution approach and could 

take advantage of allocation options discussed in this proposal 

as well as other allocation options a state might prefer. States 

could auction allowances and rebate the revenue to consumers, or 

allocate all allowances to load-serving entities, while 

mandating that the value be passed through to vulnerable 

consumers. The EPA believes that thisthe state-determined 

allocation approach offers significant advantages and solicits 

comment on how to ease its application by states. This is 

similar to the approach taken in the Cross-state Air Pollution 

Rule (CSAPR) and Clean Air Interstate Rule (CAIR) where the EPA 

adopted a rulerules allowing states to submit state 

implementation plans (SIPs) with provisions replacing the 

allowance-distribution provisions in the CSAPR or CAIR FIPs, 

respectively, while remaining in the CSAPR trading programs 

under the CSAPRthose FIPs (76 FR 48208; August 8, 2011)., 71 FR 

25328; April 28, 2006). In both CSAPR and CAIR, some states have 

chosen to determine their own allocations under the FIPs. This 

form of SIP that can replace the allowance-distribution 

provisions in CSAPR or CAIR is termed an “abbreviated SIP 

revision.” In this proposed mass-based trading federal plan, the 

EPA proposes that a state may choose to submit a “state 

allowance-distribution methodology” (analogous to an abbreviated 
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SIP revision) to replace the federal-plan allowance-distribution 

provisions with allowance-distribution provisions of its 

choosing. 

The mechanism the agency envisions is in the nature of a 

partial state plan or (for any future changes in a state’s 

allocation methodology) a partial state plan revision. (We 

request comment below on the advantages and disadvantages of 

allowing a state to handle allocations via a delegation of 

federal plan authority.) In general, under the proposed 

approach, the procedural requirements states and the agency must 

follow, including public notice requirements, for the submission 

and approval of state plans, would be required here.

The EPA intends to provide the states with substantial 

flexibility in choosing approaches to distribute their

allowances in a state allowance-distribution methodology. The 

EPA proposes that a state may choose any approach, including 

auctions or other methods the EPA is not proposing here, 

provided the state’s approach addresses leakage. and also 

implements the Clean Energy Incentive Program The EPA is also 

requesting comment on any other appropriate constraints to 

impose on state allowance-distribution methodologies.

The Clean Power Plan EGs require mass-based state plans to 

include a demonstration that they have addressed the risk of 
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leakage, and the EGs provide several options for doing so (Clean 

Power Plan EGs, section VIII.L). 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. The EPA 

believes that a state allowance-distribution methodology, which 

would replace the federal-plan allocation provisions, must also 

address leakage. The EPA proposes that a state allowancedistribution methodology must address leakage by providing 

incentive to counteract leakage, e.g., by including allowance 

set-asides like the output-based allocation and RE set-asides 

detailed in section V.D.3, or other allocation approaches 

designed to counteract leakage. The EPA requests comment on this 

proposed approach for addressing leakage in a state allowancedistribution methodology and on any other approaches for doing 

so. The EGs provide an additional option for state plans to 

address leakage, where a state would provide a demonstration 

that leakage will not occur (without implementing any of the 

strategies specified in the EGs) due to specified 

characteristics of the state (Clean Power Plan EGs, section 
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VIII.L). 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 provide for a Clean Energy 

Incentive Program (section VIII in 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.

Under the proposed approach of providing for states to 

determineddetermine their allowance distribution approaches in 

the federal plan mass-based trading program, the affected EGUs 

in a state that submitted a state allowance-distribution

methodology, which the EPA approved, would participate in the 

federal plan mass-based trading program, but with allowance 

distribution determined by the state instead of by the EPA.

The EPA proposes that a state must submit to the 

Administrator tables specifying the unit-level allowances in an 

electronic format specified by the Administrator and by the 

specified deadlines applicable to each compliance period (see 

Table &&& for proposed submission deadlines).
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The EPA proposes that a state may submit a state allocation 

methodology for any compliance period, including the first 

compliance period, which would comprise the years 2022, 2023,

and 2024 if the EPA finalizes a three-year compliance period..

The EPA proposes that a state submitting a state allowancedistribution methodology to modify the federal plan allowancedistribution provisions must do so for all years within a 

compliance period (e.g., for all three years in a three-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 

the state allowance-distribution provisions would apply, the 
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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.111 The EPA proposes that a state’s 

allowance-distribution provisions would replace the EPA’s 

allocation provisions completely – a state would not have the 

option of implementing only a portion of its allocations (e.g.,

only set-asides) and having the EPA implement the remainder of 

its allocations. Additionally, the EPA proposes that a state 

allowance-distribution methodology would have tomust provide for 

allowances to be issued in metric tons if EPA finalizes the 

proposed approach of issuing federal plan allowances in metric 

tons; the EPA proposes that a state allowance-distribution 

methodology would have to provide for allowances to be issued in 

short tons if the EPA finalizes the alternative of issuing 

federal plan allowances in short tons.

The allocation (or auction) of allowances would be final 

 

111 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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and could not be subject to modification. Additionally, the 

state’s provisions could not change any other provisions of the 

proposed mass-based trading program with regard to the 

allowances (e.g., the deadlines for allocation recordation, or 

requirements for transfer or use of allowances) or any other 

aspect of such trading programs.

In order for a state allowance-distribution methodology’s 

provisions to replace the EPA’s allowance-distribution 

provisions for a given compliance period, a state would have to 

submit the state allowance-distribution methodology by a 

deadline that would provide the agency sufficient time to review 

and approve it, and to submit the allowance table meeting the 

specified electronic format by a deadline that would provide 

sufficient time to record the unit-by-unit allowances in source 

accounts. The EPA believes that about twelve 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 &&&, for 

submission to the agency of state allowance-distribution

methodologies and unit-level allowances, and for EPAthe EPA’s

recordation of allowances, for each compliance period. The EPA 
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would review and approve state allowance-distribution 

methodologies in the twelve months between the proposed deadline 

for states to submit their methodologies and the proposed 

deadline for states to submit unit-level allowance tables. The 

proposed deadline for submission of allowance tables is three

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 &&&. 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 two-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 
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plan allocations only in the absence of an approved state plan 

or approved state allowance-distribution methodology. The EPA 

proposes to record in source accounts allowances that are 

determined by any state as soon as feasible after approval of a 

state allowance-distribution methodology and not to wait until 

the allowance recordation deadline to do so.

In section V.D.2, the EPA proposes the allowance 

recordation deadline seven 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 thirteen months prior 

to the start of the compliance period (i.e., December 1 of the 

year two years before the compliance period starts). If the EPA 

adopted the earlier recordation deadline on which it requests 

comment, 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 bywith a state plan for a future 

compliance period for which allowances have already been 

recorded, as discussed below in section V.F.
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The agency requests comment on the proposed approach to 

allow states to determine allocations via state allowancedistribution methodologies and replace the federal-plan 

allowance-distribution provisions. The EPA requests comment on 

the proposed schedule for submitting state allowance 

distribution methodologies to the agency, for submitting the 

resulting unit-level allowance tables to the agency, and for the 

agency to record allowances. The EPA requests comment on its 

proposed approach of not replacing EPA-determined allocations 

for a compliance period for which allowances have already been 

recorded. The agency also requests comment on an alternative 

approach where a state could notify the EPA of its intent to 

submit a state allowance-distribution methodology in advance, in 

which case the agency would hold off on recording EPA-determined 

allocations to allow more time for state-determined allowances

to be recorded, similar to the alternative timing approach 

discussed in section V.F.

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 
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– to a state that wishes to determine its allowance-distribution

provisions. The EPA requests comment on the relative efficiency 

and ease of implementation of the two approaches (the state 

allowance-distribution methodology described above, or the 

partial delegation). The agency requests comment on whether the 

partial delegation approach would provide sufficient flexibility 

for a state to choose any method to distribute its allowances 

including approaches that the EPA is not proposing here. See 

further discussion of delegations in section VI in 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 three-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 
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commencing in 2025. The EPA is proposing this stipulation for 

the timing of replacing a federal plan with a state plan due to 

the need to avoid disruption to sources already subject to the 

mass-based trading federal plan. Without this stipulation, a 

state might withdraw from the mass-based trading program in the 

middle of a compliance period even though allowances that 

authorize emissions throughout that entire compliance period

would already be in circulation. In that circumstance, the EPA 

would then need to address whether and how to remove those 

allowances from circulation to prevent inflation of the 

allowable emissions at affected EGUs in the remaining states 

subject to the federal plans beyond the levels specified in the 

Clean Power Plan EGs. The EPA believes it is more reasonable to 

avoid this potential disruption by requiring that the 

replacement of a federal plan with a state plan be scheduled to 

coincide with the conclusion of the last compliance period for 

which allowances under the federal plan have already been 

recorded for that state. The EPA requests comment on other 

approaches to provide a smooth transition from federal-plan 

implementation to implementation by state plans, and on its 

proposed approach of not replacing a federal plan for any 

compliance period for which allowances were already recorded.

The agency requests comment on an alternative of providing 
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for a state to give notice to the EPA of its intent to submit a 

state plan to replace the federal plan (or a state allowancedistribution methodology to replace federal-plan allocations), 

and for the agency to delay recording federal-plan allocations

for sources in that state until a later date than proposed. The 

EPA requests comment on whether this alternative would help 

smooth the transition from federal-plan implementation to stateplan implementation, and on the trade-off between recording 

allowances in a timely way and providing this increased timing 

flexibility.

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 
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(i.e., a facility level account for all affected EGUs at the 

facility) and general accounts (i.e., accounts for other 

entities such as companies and brokers), deduction of CO2

allowances for compliance purposes, and transfers of allowances 

between accounts. The primary role of ATCS is to provide an 

efficient, automated means for affected EGUs to comply, and for 

the EPA to determine whether affected EGUs are complying, with 

the emissions limitations and any other requirements of the 

mass-based trading program. ATCS would also provide data to the 

allowance market and the public, including a record of ownership 

of allowances, dates of allowance allocations, allowance 

transfers, buyer and seller information, serial numbers of 

allowances transferred, emissions, and compliance information.

This information would be publicly available on the EPA’s web 

site and in annual progress reports.

1. Designated Representatives and Alternate Designated 

Representatives

Sections XX.XX through XX.XX This section would establish 

the procedures for certifying and authorizing the designated 

representative, and alternate designated representative, of the 

owners and operators of an affected EGU and for changing the 

designated representative and alternate designated 

representative. These sections would also describe the 
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designated representative’s and alternate designated 

representative’s responsibilities and the process through which 

he or she could delegate to an agent the authority to make 

electronic submissions to the Administrator. These provisions 

would be patterned after the provisions concerning designated 

representatives and alternates in prior EPA-administered trading 

programs. 

The designated representative would be the individual 

authorized to represent the owners and operators of each 

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 
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for the affected EGU and for the designated representative and 

alternate; the name of every owner and operator of the affected 

EGU; and certification language and signatures of the designated 

representative and alternate. All submissions (e.g., monitoring 

plans, monitoring system certifications, and allowance 

transfers) for an affected EGU would have to be submitted, 

signed, and certified by the designated representative or 

alternate. Further, upon receipt of a complete certificate of 

representation, the Administrator would establish a compliance 

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 
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allowing the designated representative and alternate to delegate 

authority to make electronic submissions on his or her behalf.

The designated representative and alternate could designate 

agents to submit electronically certain specified documents. The 

previously-described requirements for designated representatives 

and alternates would provide regulated entities with flexibility 

in assigning responsibilities under the mass-based trading 

program, while ensuring accountability by owners and operators 

and simplifying the administration of the proposed mass-based 

trading program. 

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

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

obtain and disseminate timely, accurate allowance price 

information than is the EPA. For example, because not all 

allowance transfers are immediately reported to the 

Administrator for recordation, the Administrator would not be 

able to ensure that any reported price information associated 

with the transfers would reflect current market prices.

3. Compliance and General Accounts 

This section describes two types of Allowance Tracking and 

Compliance system accounts: Compliance accounts, one of which 

the Administrator would establish for each facility with an 

affected EGU upon receipt of the certificate of representation 

for the facility; and general accounts, which could be 

established by any entity upon receipt by the Administrator of 

an application for a general account. A compliance account would 

be the account in which any allowances used by an affected EGU

for compliance with the emissions limitations would have to be 

held. The designated representative and alternate for the 

affected EGU would also be the authorized account representative 

and alternate for the compliance account. Using facility-level, 

rather than electric generating unit-level accounts, would 

provide owners and operators more flexibility in managing their 
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allowances for compliance, without jeopardizing the 

environmental goals of the mass-based trading program, because 

the facility-level approach would avoid situations where an EGU 

would hold insufficient allowances and would be in violation of 

allowance-holding requirements even though EGUs at the same 

facility had more than enough allowances to meet these 

requirements for the entire facility. Facility-level compliance 

would also be consistent with other EPA-administered mass-based 

trading programs. [citations needed]

General accounts could be used by any person or group for 

holding or trading allowances. However, allowances could not be 

used for compliance with emissions limitations so long as the 

allowances were held in, and not properly and timely transferred 

out of, a general account. To open a general account, a person 

or group would have to submit an application for a general 

account, which would be similar in many ways to a certificate of 

representation. The application would include, in a format 

prescribed by the Administrator: the name and identifying 

information of the individual who would be the authorized 

account representative and of any individual who would be the 

alternate authorized account representative; an identifying name 

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

interest with the respect to allowances held in the account; and 
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certification language and signatures of the authorized account 

representative and alternate. The authorized account 

representative and alternate would be authorized upon receipt of 

the application by the Administrator. The provisions for 

changing the authorized account representative and alternate, 

for changing the application to take account of changes in the 

persons having an ownership interest with respect to allowances, 

and for delegating authority to make electronic submissions 

would be analogous to those applicable to comparable matters for 

designated representatives and alternates. 

4. Recordation of Allowance Allocations and Transfers

By June 1, 2021, the Administrator would record allowance 

allocations for electric generating units 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 
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another would be quite simple. A transfer would be submitted 

providing, in a format prescribed by the Administrator, the 

account numbers of the accounts involved, the serial numbers of 

the allowances involved, and the name and signature of the 

transferring authorized account representative or alternate. If 

the transfer form containing all the required information were 

submitted to the Administrator and, when the Administrator 

attempted to record the transfer, the transferor account 

included the allowances identified in the form, the 

Administrator would record the transfer by moving the allowances 

from the transferor account to the transferee account within 5 

business days of the receipt of the transfer form. 

5. Compliance with Emissions Limitations

Once the compliance period has ended (e.g., at midnight on 

December 31, 2024 for the first compliance period), facilities 

with affected EGUs would have a window of opportunity following 

the compliance period to evaluate their reported emissions and 

obtain any allowances that they might need to cover their 

emissions during the compliance period. For example, the 

allowance transfer deadline for the first compliance period

would be midnight on NovemberMay 1, 2025 (the EPA is also 

requesting comment on anearlier or later allowance transfer 

deadline of June 1 or March 1deadlines). Each allowance issued 
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in the proposed mass-based trading program would authorize 

emission of one ton of CO2 and so would be usable for compliance, 

for the compliance period that includes the year for which the 

allowance was allocated or a later compliance period. 

Consequently, each affected EGU would need –-, as of the 

allowance transfer deadline –- need, to have in its facility

compliance account, or to have a properly submitted transfer 

that would move into its compliance account, enough allowances 

usable for compliance to authorize its total emissions for the 

compliance period. The authorized account representative could 

identify specific allowances to be deducted, but, in the absence 

of such identification or in the case of a partial 

identification, the Administrator would deduct on a first-in, 

first-out basis. Deducting allowances may have tax and 

accounting implications, so having a default deduction method 

provides the representatives with certainty regarding which 

allowances will be deducted for compliance. Allowances that are 

deducted for compliance will remain in the system in an EPA 

account, which ensures they will not be used again. If an 

affected EGU a facility were to fail to hold sufficient 

allowances for compliance by all affected EGUs at the facility, 

then the owners and operators of the facility and each affected 

EGU at the facility would have to provide, for deduction by the 
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Administrator, two allowances allocated for the compliance

period in the next year for every allowance that the owners and 

operators failed to hold as required to cover emissions. This

submittal of two times the allowances required for the prior 

period is an ongoing obligation until compliance is achieved, 

and there is an ongoing obligation to comply in the current 

period. In addition, thethese owners and operators would be 

subject to civil penalties for each violation in accordance with 

the Clean Air Act, with each ton of unauthorized emissions and 

each day of the compliance period involved constituting a 

violation of the CAA.

The EPA believes that it is important to include a 

requirement for an automatic deduction of allowances. The 

deduction of one allowance per allowance that the owners and 

operators failed to hold would offset this failure. The 

automatic deduction of another allowance per allowance that the 

owners and operators failed to hold that could not be avoided, 

regardless of any explanation provided by the owners and 

operators for their failure, would provide a strong incentive 

for compliance with the allowance-holding requirement by 

ensuring that non-compliance would be a significantly more 

expensive option than compliance. Such automatic deductions have 

been successfully used in prior programs including the Clean Air 
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Interstate Rule, achieving compliance rates close to 100 

percent.

6. Other Allowance Tracking and Compliance Operations Provisions

These sections also would provide that the Administrator 

could, at his or her discretion and on his or her own motion, 

correct any type of error that he or she finds in an account in 

the Allowance Tracking and Compliance System. In addition, the 

Administrator could review any submission under the mass-based 

trading program, make adjustments to the information in the 

submission, and deduct or transfer allowances based on such 

adjusted information. These provisions are a standard part of 

other trading programs administered by the EPA including the 

Acid Rain 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 
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the quarter. The reporting would be in accordance with 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 

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 

Mercury and Air Toxics Standards (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
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be used to calculate a CO2 mass or CO2 emission rate for this 

program. RGGI, ARP, MATS and this rule all refer to CEMS 

installed and certified in accordance with 40 CFR part 75. RGGI 

and ARP currently require the reporting of CO2 mass emissions on 

an hourly basis and cumulative totals at the end of each 

calendar quarter. The same monitors and data collected may be 

used for multiple purposes for RGGI, ARP, MATS and this rule.

Relying on the same monitors that are certified and quality 

ensured in accordance with 40 CFR part 75 ensures cost 

efficient, consistent, and accurate data that may be used for 

different purposes for multiple regulatory programs.

The majority of the units covered by this rule are already 

affected by the Acid Rain and/or Regional Greenhouse Gas 

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]..

The EPA also solicits comment on measures that could monitor 
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the environmental integrity of a federal plan. As discussed 

previously in [&&&x], differences in generation incentives could 

lead to artificially increased generation by new EGUs or EGUs in 

neighboring states that are subject to different emission 

standards. Earlier sections discussed allocation options and other 

design strategies to address potential emissions leakage in a 

federal plan [&&&citation]. These efforts could be complemented by 

an emission and generation monitoring program that would help track 

key trends, suggest further design opportunities to support 

environmental integrity, and inform any related future decisions 

or policies. 

In particular, the EPA notes that the Regional Greenhouse Gas 

Initiative, in its founding MOU, specifically directed efforts to 

study this potential concern and provided recommendations to 

monitor emissions leakage. RGGI’s recommendations included 

producing detailed, periodic monitoring reports that tracked 

generation and its related environmental attributes, both for 

generation inside the RGGI region and generation located outside 

the RGGI region but serving load in the RGGI region.112 These 

monitoring reports rely on information collected and tracked by 

independent system operators in generator attribute tracking 

 

112 http://www.rggi.org/docs/il_report_final_3_14_07.pdf.
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systems. Part of RGGI’s recommendations included exploring 

necessary improvements to existing generator attribute tracking 

systems in order to support their ability to: determine how much 

electricity is being used in areas subject to RGGI (including 

supply by generation from within and outside of the RGGI region); 

determine and track the environmental attributes associated with 

those sources of generation, ideally reflecting the specific 

generation unit but alternatively based on applicable systemaverage attributes; identify units within the RGGI region and track 

their regulatory status; and other attributes. 

The EPA solicits comment on including a monitoring system to 

track program integrity as part of the federal plan. In particular, 

the EPA solicits comment on the agency’s legal authority to 

undertake relevant measures to develop and apply an appropriate 

monitoring program as part of the federal plan. The EPA also 

requests comment on the proper design of a program. Such a 

monitoring system could be used to track overall electricity 

consumed and generated in-state. It could also be designed to track 

the demand that is being met by different categories of units 

serving load in-state: (1) in-state units covered by the federal 

plan; (2) in-state uncovered units; and (3) out-of-state units. At 

the same time, it would monitor the environmental attributes of 

electricity supply, either by developing systems to track the CO2
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emissions performance associated with individual identified units, 

or by developing system-average emission rates for each of the 

three different categories of units serving in-state load.

This type of program could monitor environmental integrity by 

tracking changes in the CO2 emissions from generation not covered 

by the federal plan, i.e., uncovered in-state units or imports 

from neighboring states covered by different plans. One possible 

method would be to compare the change in emissions totals derived 

by multiplying the marginal increase in load served in-state by 

generation not subject to the federal plan by its applicable CO2

emission attributes compared to their historic or projected 

baseline generation. The EPA solicits comment on the existing 

availability of data on key indicators, options for acquiring and 

tracking any key data that is not yet widely available, and methods 

for analyzing that information to assess any potential change in 

environmental performance of a federal plan due to artificial 

differences in generation incentives.

VI. Implementation of the Federal Plan and Delegation

Background of Authority

Under section 111(d) of the CAA, the EPA adopts Emission 

Guidelines (EG) that are then implemented when the EPA approves 
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a state or tribal113 plan or promulgates a federal plan that 

implements and enforces the EG for affected EGUS in states notor 

areas of Indian country114 without an approved state or tribal 

plan. Congress has determined that the primary responsibility 

for air pollution prevention and control rests with state and 

local agencies, while also recognizing that “Federal ... 

leadership is essential for the development of cooperative 

Federal, State, regional, and local programs to prevent and 

control air pollution.” (See section 101(a)(3) and (4) of the 

CAA.) Congress has also provided for Indian tribes meeting 

specified eligibility criteria to implement the Clean Air Act 

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 section 

111(d), states and eligible tribes may still seek a delegation 

of authority from the EPA to implement a federal plan, similar 

 

113 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.

114 As discussed in detail in (citation), in adopting a federal 

plan implementing the EG in areas of Indian country containing 

EGU, the EPA must determine that such a plan is “necessary or 

appropriate” to protect air quality. See, 40 CFR 49.11(a).
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to the ability to take delegated authority under other CAA 

programs. The EPA encourages states and eligible tribes that do 

not submit approvable plans to request delegation of the federal 

plan if they wish to have primary responsibility for 

implementing the EG. Approved and effective state or tribal 

plans or delegation of the federal plan is the EPA’s preferred 

outcome in many circumstances where the EPA believes that state 

and local, or tribal, agencies have practical knowledge and 

enforcement resources critical to achieving the highest rate of 

compliance. Legally, delegation of a standard or requirement 

means that obligations a source may have to the EPA under a 

federally promulgated standard become obligations to a state or 

tribe (except for functions that the EPA retains for itself) 

upon delegation.115 116 Delegation of the federal plan and 

Retained Authorities

 

115 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.

116 We note that issuance of a title V permit is not equivalent to 

the approval of a state plan or delegation of a Federal Plan. This 

has been discussed in prior rulemakings, see, e.g., Proposed 

Federal Plan for Commercial Industrial Solid Waste Incinerators 

(CISWI) (67 FR 70640, 70652; Nov. 25, 2002); Final Federal Plan 

for CISWI (68 FR 57518, 57535; Oct. 3, 2003).
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A. Delegation of the Federal Plan and Retained Authorities

If a state or tribe117 intends to take delegation of the 

federal plan, the state or tribe should submit to the 

appropriate EPA Regional Office a written request for delegation 

of authority. The state or tribe should explain how it meets the 

criteria for delegation. See generally “Good Practices Manual 

for Delegation of NSPS and NESHAP” (EPA, February 1983). The 

letter requesting delegation of authority to implement the 

federal plan should: (1) demonstrate that the state or tribe has 

adequate resources, as well as the legal and enforcement 

authority to administer and enforce the program, (2) include an 

inventory of affected EGUs, which includes those that have 

ceased operation but have not been dismantled, include an 

inventory of the affected units’ air emissions and a provision 

for state or tribal progress reports to the EPA, (3) certify 

that a public hearing ishas been held on the state or tribal

delegation request, and (4) include a memorandum of agreement 

between the state or tribe and the EPA that sets forth the terms 

and conditions of the delegation, the effective date of the 

agreement and the mechanism to transfer authority. Upon 

 

117 A tribe interested in taking delegation of the federal plan 

must also apply, and be approved by EPA, for TAS eligibility for 

that purpose. 40 CFR part 49.
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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.)

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 section 111(d) Clean 

Power Plan:

(1) [&&& DO WE HAVE A LIST OF ITEMS FOR WHICH EPA 

PREFERS TO MAINTAIN AUTHORITY?]
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Today’s 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 

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. 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 
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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 aan approved state or tribal

plan, the federal plan would no longer apply to EGUs covered by 

such a plan and the state or local agency, or the tribe, would 

implement and enforce the state or tribal plan in lieu of the 

federal plan. The timing of effectiveness of aan approved state

or tribal plan in this circumstance may depend in part on the 

need to ensure a smooth transition and maintain regulatory 

certainty. Thus, for example, under a mass-based federal plan, 

we propose to handle these transitions so that they coincide 

with the compliance periods. The approval of a state or tribal

plan would also involve a public comment process, which would 

give interested stakeholders including any affected EGUs, the 

opportunity to comment. This will assist in ensuring that 

compliance, program integrity, electric reliability, and other 

critical factors are maintained. When an EPA Regional Office 

approves a state or tribal plan, it will amend the appropriate 

subpart of 40 CFR part 62 or 40 CFR part 49, respectively, to 
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indicate such approval, as well as the timing of its 

effectiveness.

As discussed elsewhere in this Notice, 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 

trading program, as discussed in section &&& above. 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 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.
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2. 2. State or Tribe Takes Delegation of the Federal planFlan

The EPA, in its discretion, may delegate to state or tribal 

air agencies the authority to implement this federal plan. As 

discussed above, the EPA believes that it is advantageous and 

the best use of resources for state or local agencies or tribes

to agree to undertake, on the EPA’s behalf, administrative and 

substantive roles in implementing the federal plan to the extent 

appropriate and where authorized by state or tribal law. If a 

state or tribe requests delegation, the EPA will generally 

delegate the entire federal plan to the state or tribal agency, 

thereby providing authority to the state or tribe for things 

such as administration and oversight of compliance reporting and 

recordkeeping requirements, inspections of its affected EGUs, 

and enforcement. The EPA will continue to hold inspection, 

information gathering, enforcement, and other authorities along 

with the state or tribe even when a state or tribe has received 

delegation of the federal plan. The delegation will not include 

any authorities retained by the EPA.

C. Implementing Authority

The EPA Regional Administrators have been delegated the 

authority for implementing the federal plan. All reports 

required by the federal plan should be submitted to the 
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appropriate Regional Administrator. Section II.C. of this 

preamble includes Table [&&&] that lists names and addresses of 

the EPA Regional Office contacts and the states they cover.

With respect to the administration of a federal trading 

program in any final federal plan for a state or tribe, group of 

states or combined group of states and tribes, the Office of Air 

and Radiation within the Headquarters of the EPA is proposed to 

be the primary office within the agency with delegated 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)(2) authorizes) of the Clean Air Act and 40 CFR part 49 

authorize the Administrator to treat an Indian tribe in the same 

manner as a state for this EGU requirement (TAS).(TAS) for 

purposes of developing and implementing a tribal plan 

implementing the EG. See 40 CFR 49.3; see also ‘‘Indian Tribes: 

Air Quality Planning and Management,’’ hereafter ‘‘Tribal 

Authority Rule,’’ (63 FR 7254, February 12, 1998). We invite 

comments from anytribes with EGU in their area of Indian country 

to comment on the affected tribes whether they are 

interestedlevel of their interest, if any, in developing their 
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own planplans. 

The EPA is proposing in today’s action to find that it is 

necessary andor appropriate to regulate affected EGUs in each of 

the three areas of Indian country that have affected EGUs under 

the proposed federal plan. The EPA is authorized to directly 

implement the CAAEG in Indian country when it determines 

pursuant tofinds, consistent with the authority of section 

301(d) and which EPA has exercised in 40 CFR 49.11, that it is 

necessary or appropriate to do so. In the final Emission 

Guidelines, the EPA finalized performance goals for the four 

facilities located in three areas of Indian country with 

affected EGUs: lands of the Navajo NationNation’s reservation, 

lands of the Ute Tribe of the Uintah and Ouray Reservation, and 

lands of the Fort Mojave Tribe.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, inon the Fort Mojave 

Indian countryReservation geographically located within Arizona; 

the Navajo Generating Station, inon the Navajo Indian 

countryReservation geographically located within Arizona; the 
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Four Corners Power Plant, inon the Navajo Indian

countryReservation geographically located within New Mexico; and 

the Bonanza Power Plant, in Uteon the Uintah and Ouray Indian 

countryReservation geographically located within Utah. The 

emission performance targets for these areas were finalized 

along with those for EGU located in the rest of the country in 

the final EGs. &&&citation. 

In today’s action, we are proposing to find that it is 

necessary or appropriate, in each of the three areas of Indian 

country that have affected EGUs, to establish a federal plan that 

applies to the four power plants located on the Navajo Nation, the 

Fort Mojave Indian Reservation, and the Uintah and Ouray 

Reservation of the Ute Tribe. The affected EGUs located on the 

Navajo Nation are in an area of Indian country located within the 

continental United States, 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 
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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 hashave expressed a clear intent to develop and seek 

approval of a tribal implementation plan. Absent Thus, absent a 

federal plan, the significant emissions from these four power 

plants wouldcould go unregulated by the Clean Power Plan.

Because the agency has finalized emission performance targets 

for these power plants in the EGs, there is, in our view, little 

benefit to be had by not proposing to include them in a federal 

plan now and a potentially significant downside to not doing so; 

the reductions the EPA has determined are achievable in the EGs 

would become more difficult and costly for these power pantsplants 

to achieve if they are delayed in entering into the trading program 

the agency intends to establish. In order to meet the performance 

targets, we are anticipating that the affected EGUs may need to 

secure allowances or ERCs (depending on the approach ultimately 

finalized) during the compliance periods. They may also be able to 

generate and sell compliance instruments by participating in the 

trading program. Thus, proposing a finding that it is necessary or 

appropriate to establish one or more federal plans providing the 
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ability to participate in a rate- or mass-based trading program is 

in the interest of these four power plants located in areas of 

Indian country.. We believe that this together with the facts that, 

as indicated above, all four EGU are interconnected with the 

western electricity grid and are owned and operated by an entity 

that generates and provides electricity to customers in several 

states thereby making it potentially disruptive and inequitable 

not to include them in one or more federal plans on the same 

schedule as other affected EGU strongly supports proposing to find 

that it is necessary or appropriate to establish one or more 

applicable federal plans at this time.

We recognize that the governments of these tribes may still 

choose to seek TAS to develop a tribal plan, and this proposed 

determination does not preclude the tribes from taking such 

actions. We also note that this proposed determination does not 

preclude these tribes from seeking TAS and receiving delegation to 

administer aspects of theany applicable federal plan. that is 

ultimately promulgated. In the event a federal plan is needed, 

proposing a necessary or appropriate determinationfinding at this 

time will allow 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 
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of the Uintah and Ouray Reservation during the comment period for 

this proposal, and prior to taking any action to finalize a 

necessary or appropriate determination and/or a federal 

planfinding and/or a federal plan. Comments on the appropriateness 

of the proposed finding, should be submitted 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 111(d) 

guideline, “Carbon Pollution Emission Guidelines for Existing 

Stationary Sources: Electric Utility Generating Units,” in this 

action, in addition to the proposed federal plans and model 

trading rules, the EPA is also proposing to amend the framework 

regulations and update the process for acting on section 111(d) 

state plans under Subpart B of 40 CFR Part 60. These changes 

would be applicable to any future section 111(d) rules going 

forward, not just the Clean Power Plan EGs. The EPA proposes six 

changes to the 111(d) process in the framework regulations to 

include: (1) partial approval/disapproval mechanisms similar to 

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

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

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

Section 110(k)(5); (4) an error correction mechanism similar to 
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section 110(k)(6); (5) completeness criteria and a process for 

determining completeness of state plans and submittals similar 

to section 110(k)(1) and (2); and (6) updates to the deadlines 

for EPA actionthe 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 section 111(d) 

modifies or reconstructs. We believe these changes will 

significantly streamline the state plan review and approval 

process, be more respectful of state processes, and generally 

enhance the administration of the 111d program.

Section 111(d)(1) provides that the EPA “shall establish a 

procedure similar to that provided by 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 111(d) plans. Notably, the CAA does not require the 

111(d) procedures to be identical to those the EPA uses under 

section 110 for SIPs.118 Therefore, the EPA interprets 111(d) to 

provide the EPA flexibility in designing procedures that reflect 

 

118 See Webster’s II New Riverside University Dictionary (Riverside 

1988) (defining “similar” to mean “resembling though not 

completely identical”).
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the structure of those used under section 110 for implementation 

plans, without requiring the EPA to exactly track SIP procedures 

when acting on 111(d) plans.

As a general matter these proposed changes would simply 

update the section 111(d) framework regulations to include 

several new, more flexible procedural tools that Congress 

introduced into section 110 in the 1990 Clean Air Act 

Amendments. The basic procedures in the 111(d) framework 

regulations were promulgated in 1975 based on the structure of 

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 111(d) regulations in a 

similar fashion. Currently, the EPA’s framework regulations for 

submittal and adoption of section 111(d) state plans do not 

explicitly provide for the EPA to use some of the same 
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procedures for approving or disapproving state plans Congress 

introduced into the SIP program in the 1990 Clean Air Act 

Amendments. The EPA is proposing to amend the procedures for 

approval or disapproval of section 111(d) state plans to reflect 

the enhancements Congress included in CAA section 110 for agency 

actions on SIPs. These proposed amendments are discussed in more 

detail below.

A. Partial Approvals/Disapprovals

First, the EPA proposes to add authority similar to that 

under section 110(k)(3) to partially approve or disapprove a 

plan.119 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 

 

119 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 section 111(d).
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approvable. Another valuable function for thisapprovableThis

mechanism are those situations where the state wishes to take 

over a discrete part of a federal plan. For instance, in 

today’sthis proposal, states will be able to seek approval of a 

partial state plan that will give them the ability to handle the 

allocation of allowances under a mass-based federal plan.

In cases where elements of a plan are functionally 

severable from each other, and one element is approvable while 

another is not, this provision will authorize the EPA to approve 

one part of a plan and disapprove the other. It will also 

authorize the EPA to accept and review a state plan that is only 

partial in nature, if identified by the state as such, so long 

as the other applicable submission requirements are met (such as 

demonstration of legal authority and completion of the public 

process). When the state submits what it intends to be a full 

state plan (rather than just a partial plan), the EPA proposes 

that the approvable portion of a plan must be functionally 

severable from the rest of the plan, and this will be the case

when the following conditions are met. First, the approvable 

portion of the plan must not depend on the rest of the plan. In 

other words, the disapproval of the remaining portion of the 

plan must not affect the portion that is approved. Second, 

approval of the approvable portion must not alter the function 
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of the submittal in a way that is contrary to the state’s

intent.

The partial disapproval would be a disapproval for the 

purposes of 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 111(d) will enable 

the EPA to approve a state to implement as much of its program 

as is consistent with a 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 section 

110(k)(4) to conditionally approve a plan. Where a state has 

submitted a plan that substantially meets the requirements of a 

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 one 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 
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section 111(d) will enable the EPA to approve a state to begin 

to administer a substantially complete program that requires 

only specific changes to be fully approvable. For example, in 

today’sthis action, we are proposing to conditionally approve

state plans that adopt the proposed model trading rule, so long 

as the state commits to adopt any changes in the final model 

trading rule necessary to ensure EG requirements are met. This 

provision is designed to authorize a state with a substantially 

complete and approvable program to begin implementing it, while 

promptly amending the program to ensure it fully complies with 

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 decades. UnderdecadUnder the Clean Power Plan 

EGs, states have many years more than a decade to fully 

implement emissions standards or state measures in order to 

ensure affected EGUs achieve the emission goals of the EGs.

Throughout this period, the EPA and the states will be 
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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 section 111(d) similar to the so-called “SIP 

call” mechanism in section 110(k)(5) will allow the agency to 

initiate a process with the state to make necessary revisions to 

ensure the plan functions properly. 

Accordingly, the EPA is proposing to amend the framework 

regulations to include a provision similar to section 110(k)(5) 

under which the EPA may find that a state’s 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 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.120

 

120 Consistent with the agency’s practice under section 110(k)(5), 
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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 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 111(d)(2)(A). A finding of failure to meet that 

new deadline triggers the EPA’s authority to issue a federal 

plan for the state. The EPA may promulgate a federal plan at any 

time following the state’s failure to timely submit an adequate 

plan that addresses the EPA’s finding.

While these authorities are important, the intention of 

having a mechanism to call for plan revisions is to have a way 

to initiate an orderly process to improve plans when they are 

not meeting program objectives. It is the EPA’s hope that a call 

for plan revision leads to a constructive dialogue with a state 

or states, and ultimately, an improved and more effective 111(d) 

plan.

Error Corrections

The EPA is also proposing that the agency can call for a 

plan revision in circumstances where a state is not implementing 

 

the EPA anticipates that a call for plan revisions under 111(d) 

will be done via notice and comment rulemaking.
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its approved state plan and, therefore, the state plan is 

substantially inadequate to provide for the implementation of 

section 111(d) standards of performance. As discussed above, the 

Act directs the EPA to develop a procedure for state plans under 

section 111(d) similar to 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 section 

111(d). Under section 110(k)(5), the EPA may call for a revision 

of a state plan “[w]henever the Administrator finds that the . . 

. plan . . . is substantially inadequate to . . . comply with 

any requirement of [the Act].” If the state does not submit a 

plan revision in response to the call to cure the failure to

provide for implementation, the EPA would have the authority to 

promulgate the federal plan being proposed.

One critical requirement of 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 
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inadequate to comply with this requirement of the Act. 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 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 section 111, this authority translates into 

the EPA calling a state plan when the agency finds that it is 

substantially inadequate to achieve the emissions reductions 

required under the EG. If a state has failed to implement its 

plan, and that failure is pervasive enough to render the 

requirements of the plan ineffective, it is reasonable for the 

EPA to find that the state plan is substantially inadequate to

achieve the emissions reductions required under the EG. The 

state’s failure to implement has revised the effect of the plan 

so that it is no longer adequate to meet the Act’s 

requirements.Error Corrections

The fourth mechanism is the error correction authority 

under section 110(k)(6). Where the EPA concludes that it has 
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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 section 110(a)(2) requires the state to 

provide notice and a public hearing on each new SIP submittal. 

Incorporating this mechanism into the 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 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 
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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 section 110(k)(1), the EPA promulgated 

completeness criteria in 1990 at Appendix V to Part 51 (55 FR 

5830; Feb. 16, 1990). The EPA proposes to adopt criteria similar 

to the criteria set out at section 2.0 of Appendix V for 

determining the completeness of submissions under section 

111(d). The completeness criteria can be grouped into: (1) 

administrative materials; and (2) technical support. The EPA 

proposes that the administrative materials requirementboth 

groups would apply forto all section 111(d) rules going forward. 

We propose technical-supportThe agency notes that the addition 

of completeness criteria that will only be applicable to state 

plansin the framework regulations does not alter any of the 

submission requirements states already have under the Clean 

Power Plan EGs, at subpart UUUU. The EPA may in the future 

propose technical support criteria that are specific to future 

111(d) rules.. 

For administrative materials, the EPA is proposing 

completeness criteria that mirror the existing administrative 
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criteria for SIP submittals because the two programs have 

similar administrative processes. The EPA proposes that a 

complete final state plan submittal under section 111(d) must 

include:

(a (1) a formal letter of submittal from the Governor or 

her designee requesting EPA approval of the plan or revision 

thereof;

(b (2) evidence that the state has adopted the plan in the 

state code or body of regulations. (That evidence shall include 

the date of adoption or final issuance as well as the effective 

date of the plan, if different from the adoption/issuance date;

(c.); (3) Evidence that the state has the necessary legal 

authority under state law to adopt and implement the plan;

(d and (4) a copy of the actual regulation, or document 

submitted for approval and incorporation by reference into the 

plan. The submittal shall be a copy of the official state 

regulation/document signed, stamped and dated by the appropriate 

state official indicating that it is fully enforceable by the 

state. The effective date of the regulation/document shall, 

whenever possible, be indicated in the document itself. The 

state’s electronic copy must be an exact duplicate of the hard 

copy. For revisions to the approved plan, the submittal shall 

indicate the changes made (for example, by 
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redline/strikethrough) to the approved plan;

(e (5) evidence that the state followed all of the 

procedural requirements of the state's laws and constitution in 

conducting and completing the adoption/issuance of the plan;

(f (6) evidence that public notice was given of the 

proposed change with procedures consistent with the requirements 

of 40 CFR 60.23, including the date of publication of such 

notice;

(g (7) certification that public hearing(s) were held in 

accordance with the information provided in the public notice 

and the state's laws and constitution, if applicable and 

consistent with the public hearing requirements in 40 CFR 60.23; 

and

(h (8) compilation of public comments and the state's 

response thereto.

These criteria, as proposed, are intended to be generic to 

all section 111(d) plans going forward., with the proviso that 

specific emission guidelines may provide otherwise. The 

technical support completeness criteria that the EPA proposes 

today are specific will also be generic to the CPP EGs at 

subpart UUUU. With respect to this set of completeness criteria, 

and consistentall section 111(d) rules, with the structure of 

the CPP Emission Guidelines, EPA is organizing the proposed 
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completeness criteria for technical support materials into three 

parts: components required for all CPP state plans; components 

required for the emission standards approach; and components 

required for the state measures approach.

same proviso. The EPA proposes that the technical support 

required for all plans must include each of the following:

(a (1) description of the plan approach and geographic 

scope;

(b;(2) identification of state CO2 interim period goal (each 

designated facility, identification of emission standards for 

2022-2029), interim steps (interim step 1 for 2022-2024; interim 

step 2 for 2025-2027; interim step the designated facilties, and 

monitoring, recordkeeping, and reporting requirements that will 

determine compliance by each designated facility; (3 for 2028-

2029) and final steps of 2030 and beyond;

(c)identification of compliance schedules and/or increments 

of progress; (4) demonstration that the state plan submittal is 

projected to achieve the state’s CO2 emission goal; and

(demissions performance under the applicable EGs; (5) 

documentation of state recordkeeping and reporting requirements 

to determine the performance of the plan as a whole.

The EPA proposes that the technical support required for 

plans using the emission standards approach must include each of 
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the following:

(a) Identification of each affected EGU, identification of 

federally enforceable emission standards for the affected EGUs, 

and monitoring, recordkeeping and reporting requirements that 

will determine compliance by each affected EGU; and

(b) Demonstrations; and (6) demonstration that each emission 

standard is quantifiable, non-duplicative, permanent, 

verifiable, and enforceable.

The EPA proposes that the technical support required for 

plans using the state measures approach must include each of the 

following:

(a) Identification of each affected EGU; identification of 

federally enforceable emission standards for affected EGUs (if 

applicable); identification of backstop of federally enforceable 

emission standards; monitoring, recordkeeping and reporting 

requirements; and

(b) Identification of each state measure, demonstration 

that each state measure is quantifiable, non-duplicative, 

permanent, verifiable, and enforceable.

The EPA proposes a process similar, though not identical, 

to that set forth in 40 CFR 51.103 and Appendix V to Part 51 to 

make completeness determinations. Similar to section 

110(k)(1)(C), under this proposal, where the EPA determines that 
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a state submission required under section 111(d) does not meet 

the minimum completeness criteria we are proposing to establish, 

the state will be considered to have not made the submission. 

The EPA further proposes that, similar to 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 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 
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the completeness process the agency will not assess the content 

of those submissions to determine if they are approvable. 

Accordingly, even when the EPA affirmatively determines that a 

submittal is complete, it does not prevent the agency from later 

finding that the state plan does not meet the requirements of 

the Emission GuidelinesEGs, including finding that the submittal 

failed to address a required element and must be disapproved.

Similarly, when a submittal is determined to be complete by 

operation of law after [six 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 
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operation of law in no way prevents the EPA from subsequently 

concluding that the state’s submission is missing a required 

element of the program and making that finding as part of a 

disapproval of the plan.

As described in the final rulemaking notice for the 111(d) 

Emission GuidelinesEGs, a state will submit all 111(d) plans 

electronically. If the EPA determines that any submission fails 

to meet the completeness criteria discussed below, the agency 

may return the plan to the state and request corrections, 

identifying the components that are absent or insufficient to 

allow the EPA to perform a review of the plan. The state will 

not have met its obligation to submit a final plan until it 

resubmits a revised state plan or supporting materials 

addressing the corrections the EPA identified in its 

incompleteness determination.

The EPA is also proposing to include an exception to the 

criteria for complete administrative materials in cases where a 

state and the EPA are “parallel processing” the final plan. 

Parallel processing allows a state to submit the plan prior to 

final adoption by the state and provides an opportunity for the 

state to consider EPAthe EPA’s comments prior to submission of a 

final plan for final review and action. The EPA would propose to 

take action on a state plan based on a proposed state 
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regulation. The EPA would only finalize the action if the state 

adopts a final plan that is legally effective under state law. 

The EPA would only approve the plan if the state addressed any 

corrections that the EPA identified in its proposed action on 

the state plan without any other material change to the plan. In 

this scenario, the state’s initial submittal would not be able 

to meet all the criteria for administrative completeness, and 

the EPA proposes to adjust those criteria as provided for in 40 

CFR Pt. 51, App. V section 2.3. Note that a plan submitted for 

parallel processing must still meet all the criteria for 

technical completeness so that the EPA and the public have a 

sufficient basis on which to evaluate and comment on the EPA’s 

proposed action.

Finally, the EPA proposes that, in the case of an initial 

submittal under the CPP Emission GuidelinesClean Power Plan EGs, 

the requirements set out at Part &&&60.5760, shall serve as the 

completeness criteria the EPA will use to determine whether the 

initial submittal is complete. If those minimal submission 

requirements have not been met, as determined by the EPA in 

accordance with &&&60.5760(b), then the state will be treated as 

having failed to submit a state plan. 

E. Update to Deadlines for EPA Actions

Finally,The EPA proposes to update the deadlines for acting 
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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 section 110(c) and 110(k) adopted in 1990. The 

framework regulations for section 111(d) state plans currently 

are parallel to the prior version of section 110. They require 

the EPA to act on a state plan or plan revision submittal within 

4 months after the date required for submission of a plan or 

plan revision. 40 CFR 60.27(b). The regulations then require the

EPA to issue a proposed federal plan in certain circumstances 

after consideration of any state hearing record, 40 CFR 

60.27(c), and require the EPA to promulgate the proposed federal 

plan within 6 months after the date required for plan 

submissions, id. 60.27(d). 

The final carbon dioxide Emission GuidelinesEGs for 

Electric Utility Generating Units (EGUs) have already adjusted 

the deadline in 60.27(b) to require the EPA to act on a state 

plan under those Emission GuidelinesEGs within 12 months (rather 

than 4 months) after the date required for submission of a plan. 

See 40 CFR 60.5715. However, the CPP Emission GuidelinesClean 

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 
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or plan revisions under 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 requiredFdrequired 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 six month deadline for issuing a final federal plan in 

60.27(d) to one year121; and, similar to the change in timing for 

 

121 As under 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 section 111(d), that failure 

does not thereby obviate or in any way remove the EPA’s authority 
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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 section 111(d)(2), Congress gave the EPA the "same" 

authority to prescribe a federal plan under 111(d) as it would 

have under 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 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 section 110(c) 

as currently enacted. Second, as a general matter, the timing 

requirements of current 60.27(c) and (d), which effectively 

require the EPA to propose and finalize a federal plan within 

six months of the deadline for state submittals, may be outdated 

and unrealistic with respect to the timelines for review of 

 

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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state plans and the time periods for action, particularly as 

informed by the agency's experience with section 110 SIPs (which 

led to the extension of the timelines and other changes to 

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 six 

months of the initial deadline for state plans is therefore 

inconsistent with this provision. Fourth, existing 60.27(c) 

tracks the prior version of section 110(c) with respect to the 

issuance of a proposed federal plan. This relatively 

prescriptive language is no longer present in section 110(c). 

The procedural requirements for rulemakings under both section 

110 and 111(d) are set out in section 307(d) of the Act, and the 

EPA believes those provisions are appropriate and adequate to 

guide its rulemaking process for section 111(d) federal plans.

The EPA invites comment on all of these proposed changes to 

the framework regulations. The EPA notes that the addition of 

these mechanisms to the framework regulations will make them 

available for all section 111(d) regulations, not just those 

under the Clean Power Plan at Subpart UUUU. 
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F. Proposed Interpretation regarding Existing Sources that Modify 

or Reconstruct

In the proposed rulemaking for the CPP, the EPA proposed 

the interpretation that if an existing source is subject to a 

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. EPA also stated 

deferral of action on this issue does not impact states’ and 

affected EGUs’ pending obligations under this final rule 

relating to plan submission deadlines, as this issue concerns

potential obligations or impacts after an existing source has 

already become subject to the requirements of a state plan. The 

EPA intends to finalize its position on this issue through this 

rulemaking, which will be well in advance of the plan 

performance period beginning in 2022, at which point state plan 

obligations on existing sources are effectuated. 

We noted in the Clean Power Plan proposal that section 

111(d) is arguably silent as to this issue. Thus, we took this 

to grant the agency the authority to provide a reasonable 
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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 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 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 section 111(d) emission guidelines are initially 

promulgated for existing stationary sources in response to 

corresponding section 111(b) standards of performance for the 

same pollutant, the statute prevents new, modified or 

reconstructed sources (including under those particular 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 111(d) emission guidelines. This 
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interpretation gives meaning to the definition of “existing 

source” in 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 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 section 111(d) 

program

G. Separate Finalization of these Changes

The agency intends to finalize these procedural changes and 

interpretation sooner than it finalizes the rest of this 

proposed action. The EPA believes these changes generally 

enhance and improve the framework regulations in a way that will 

be of benefit to the states, the EPA, and other stakeholders, 
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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 section 111(d). If the

EPA does finalize these changes sooner than the model trading 

rules or the federal plan, it will do so after the close of the 

comment period, and after consideration and response to any 

comments on these changes.

VIII. Impacts of this Action

A. Endangered Species Act 

Consistent with the requirements of section 7(a)(2) of the 

Endangered Species Act (ESA), the EPA has also considered the 

effects of this proposed rule and has reviewed applicable ESA 

regulations, case law, and guidance to determine what, if any, 

impact there may be to listed endangered or threatened species 

or designated critical habitat. Section 7(a)(2) of the ESA 

requires federal agencies, in consultation with the U.S. Fish 

and Wildlife Service (FWS) and/or the National Marine Fisheries 

Service, to ensure that actions they authorize, fund, or carry 

out are not likely to jeopardize the continued existence of 

federally listed endangered or threatened species or result in 
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the destruction or adverse modification of designated critical 

habitat of such species. 16 U.S.C. 1536(a)(2). Under relevant 

implementing regulations, 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 

its habitat.122 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 

 

122 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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causal connection between the federal action, the effect in 

question, and the listed species, andif the effect is indirect, 

it must be reasonably certain to occur.

The EPA has considered the effects of this proposed rule 

and has reviewed applicable ESA regulations, case law, and 

guidance to determine what, if any, impact there may be to 

listed species or designated critical habitat for purposes of 

section 7(a)(2) consultation. The EPA notes that the projected 

environmental effects of this proposal are, like the Emission 

GuidelinesEGs that it implements, positive: reductions in 

overall GHG emissions, and reductions in PM and ozone-precursor 

emissions (SO X and NO X), for EGUS that will be covered by the 

federal plan. SOX and NOX), for EGUS that will be covered by the 

federal plan. However, the EPA’s assessment that the rule will 

have an overall net positive environmental effect by virtue of 

reducing emissions of certain air pollutants does not address 

whether the rule may affect any listed species or designated 

critical habitat for ESA section 7(a)(2) purposes and does not 

constitute any finding of effects for that purpose. The fact 

that the rule will have overall positive effects on the national 

and global environment does not mean that the rule may affect 

any listed species in its habitat or the designated critical 

habitat of such species within the meaning of ESA section 
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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 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.123 The 

DOI Solicitor concluded that where the effect at issue is 

climate change, proposed actions involving GHG emissions cannot 

pass the “may affect” test of the section 7 regulations and,

thus, are not subject to ESA consultation. 

The EPA has also previously considered issues relating to GHG 

 

123 See, e.g., 73 FR 28212, 28300 (May 15, 2008); Memorandum from 

David Longly Bernhardt, Solicitor, U.S. Department of the Interior 

re: “Guidance on the Applicability of the Endangered Species Act’s 

Consultation Requirements to Proposed Actions Involving the 

Emission of Greenhouse Gases” (Oct. 3, 2008).
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emissions in connection with the requirements of ESA section 

7(a)(2). EPA discussed this In the proposed Emissions Guidelines, 

see 79 FR 34933-34, notingfinal EGs, the agency noted that,

although the GHG emission reductions projected for the Emissions 

Guidelines wereare large (the highest estimate isestimated

reductions of 555 MMTabout 415 million short tons of CO2 in 2030

relative to the base case), the EPA evaluated larger reductions in 

assessing this same issue in the context of the light duty vehicle 

GHG emission standards for model years 2012-2016 and 2017-2025. 

EPA concluded there that it knew of “There the agency projected 

emission reductions over the lifetimes of the model years in 

question,124 which are roughly five to six times those projected 

above and, based on air quality modeling of potential environmental 

effects, concluded that “EPA knows of no modeling tool which can 

link these small, time-attenuated changes in global metrics to 

particular effects on listed species in particular areas. 

Extrapolating from global metric to local effect with such small 

numbers, and accounting for further links in a causative chain, 

remain beyond current modeling capabilities.” EPA, Light Duty 

Vehicle Greenhouse Gas Standards and Corporate Average Fuel 

Economy Standards, Response to Comment Document for Joint 

 

124 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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Rulemaking at 4-102 (Docket EPA-OAR-HQ-2009-4782); see also 79 FR 

34934. The EPA believes that the same conclusions apply to the 

present proposal, given that the federal plan will implement only 

a subset of the reductions projected from the Emission Guidelines 

as a whole (i.e., for affected EGUs in states without approved 

plans), and the projected CO 2 emission reductions from the 

Emission Guidelines are less than those projected for either of 

the light duty vehicle rules.). The EPA reached this conclusion 

after evaluating issues relating to potential improvements 

relevant to both temperature and oceanographic pH outputs. The 

EPA's ultimate finding was that “any potential for a specific 

impact on listed species in their habitats associated with these 

very small changes in average global temperature and ocean pH is 

too remote to trigger the threshold for ESA section 7(a)(2).” Id.

The EPA believes that the same conclusion applies to the present 

rule. See, e.g., Ground Zero Center for Non-Violent Action v. U.S. 

Dept. of Navy, 383 F. 3d 1082, 1091-92 (9th Cir. 2004) (where the 

likelihood of jeopardy to a species from a federal action is 

extremely remote, 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 
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projecting substantial reductions of SOXSO2 and NOx as a 

collateral consequence of this proposal (which will be, as 

stated above, only a subset of the total reductions from the 

Emissions Guidelines). However, CAA section 111(d) cannot 

directly control emissions of criteria pollutants. And 

furthermore, a federal plan under section 111(d)(2) does no more 

than prescribe emissions standards of the same stringency as the 

corresponding Emission Guidelines.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. 

Section 7(a)(2) consultation thus is not required with respect 

to the projected reductions of criteria pollutant emissions. See

50 CFR 402.03; see also WildEarth Guardians v. U.S. Envt’l 

Protection Agency, 759 F.3d 1196, 1207-10 (10th Cir. 2014) ((the 

EPA has no duty to consult under section 7 of the ESA regarding 

hazardous air pollutant controls that it did not require -- and 

likely lacked authority to require -- in a federal 

implementation plan for regional haze controls under section 

169A of the CAA.).

Finally, EPA considered whether any other relevant effects 

(beyond reduction in air pollutants) may result from the 

establishment of standards of performance for existing affected 
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EGUs and implementing and enforcing those standards. In this 

respect, this proposal is different from the Emissions 

Guidelines in that it would set in place a federal plan that 

will set standards of performance and provide for their 

implementation and enforcement for affected EGUs not covered by 

state plans. In the Emissions Guidelines proposal, EPA 

recognized that “there are substantial questions as to whether 

any potential for relevant effects results from any element of 

the proposed rule or would result instead from the separate 

actions of states establishing standards of performance for 

existing sources and implementing and enforcing those 

standards.” See 79 FR 34934. Under a federal plan, it is EPA 

that would implement a 111(d) plan. and likely lacked authority 

to require -- in a FIP for regional haze controls under section 

169A of the CAA.).

Finally, the EPA has also considered other potential effects 

of the rule (beyond reductions in air pollutants) and whether any 

such effects are “caused by” the rule and “reasonably certain to 

occur” within the meaning of the ESA regulatory definition of the 

effects of an action. 50 CFR 402.02. The EPA recognizes, for 

instance, that questions may exist whether decisions such as 

increased utilization of solar or wind power could have effects on 

listed species. The EPA received comments on the EGs asserting 
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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 

111(d) plan. The EPA believes that even with this proposed federal 

plan, any effects on listed species or designated habitat are too 

uncertain to require consultation under section 7. This is so for 
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at least two reasons. First,: (1) the EPA cannot know with any 

certainty at this state 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. Second,; and (2), the federal plan as 

proposed will be implemented through some form of emissions 

trading. Emissions trading inherently provides maximum flexibility 

to individual affected EGUs to choose their method of compliance, 

including continuing to emit the relevant pollutant at historical 

rates so long as the affected EGU holds sufficient credits or 

allowances. At this stage,point, the EPA has no meaningful 

information to express in any more than the broadest terms how any 

particular affected EGU may choose to comply with the federal plan, 

should it be promulgated for them based on their location in an 

area not covered by an approved state plan. The Services have 

explained that section 7(a)(2) was not intended to preclude federal 

actions based on potential future speculative effects.125 These are 

 

125 See 51 FR at 19933 (describing effects that are “reasonably

certain to occur” in the context of consideration of cumulative 

effects and distinguishing broader consideration that may be 

appropriate in applying a procedural statute such as the National 

Environmental Policy Act, as opposed to a substantive provision 
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precisely the types of speculative future activities and effects 

currently at issue here. The EPA requests comment on its proposed 

conclusion that ESA section 7 consultation is not required for 

this action. The EPA will continue to evaluate the scope and 

potential effects of federal planning activities for this source 

category to the extent federal plans are needed and implemented in 

specific areas and over specific sources.

B. What are the Air Impacts? 

The EPA anticipates significant emission reductions under 

the final guidelines for the utility power sector. In the final 

emission guidelines, the EPA has translated the source categoryspecific CO2 emission performance rates into equivalent statelevel rate-based and mass-based CO2 goals in order to maximize 

 

such as ESA section 7(a)(2) that may prohibit certain federal 

actions); Endangered Species Consultation Handbook, U.S. Fish & 

Wildlife Service and National Marine Fisheries Service at 4-

30(March 1998) (in the same context, describing indicators that an 

activity is reasonably certain to occur as including governmental 

approvals of the action or indications that such approval is 

imminent, project sponsors’ assurance that the action will 

proceed, obligation of venture capital, or initiation of 

contracts; and noting that the more governmental administrative 

discretion remains to be exercised, the less there is reasonable 

certainty the action will proceed).
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the range of choices that states will have in developing their 

plans. Because of the range of choices available to states and 

the lack of a priori knowledge about the specific choices states 

will make in response to the final goals, the Regulatory Impact 

Analysis (RIA) for this final action presents two scenarios 

designed to achieve these goals, which we term the “rate-based” 

illustrative plan approach and the “mass-based” illustrative 

plan approach.126

Under the rate-based approach, when compared to 2005, CO2

emissions are projected to be reduced by approximately 22 

percent in 2020, 28 percent in 2025, and 32 percent in 2030. 

Under the mass-based approach, when compared to 2005, CO2

emissions are projected to be reduced by approximately 23 

percent in 2020, 29 percent in 2025, and 32 percent in 2030. The 

final guidelines are projected to result in substantial cobenefits through reductions of SO2, NOX and PM2.5 that will have 

direct public health benefits by lowering ambient levels of 

 

126 It is important to note that the differences between the 

analytical results for the rate-based and mass-based 

illustrative plan approaches presented in the RIA may not be 

indicative of likely differences between the approaches if 

implemented by states and affected EGUs in response to the final 

guidelines. 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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these pollutants and ozone. Table [X] and Table [X] shows

expected CO2 and other air pollutant emissions in the base case

and reductions under the final guidelines for 2020, 2025, and 

2030 for both rate-based and mass-based approaches.

Table [X]. Summary of CO2 and Other Air Pollutant Emission 

Reductions from the Base Case under Rate-based Illustrative Plan 

Approach

CO2

(millions

short tons)

SO2

(thousand 

short tons)

NOX

(thousand

short tons)

2020 Final Guidelines

Base Case 2,155 1,311 1,333

Final Guidelines 2,085 1,297 1,282

Emissions Reductions 69 14 50

2025 Final Guidelines

Base Case 2,165 1,275 1,302

Final Guidelines 1,933 1,097 1,138

Emissions Reductions 232 178 165

2030 Final Guidelines

Base Case 2,227 1,314 1,293

Final Guidelines 1,812 996 1,011

Emissions Reductions 415 318 282

Source: Integrated Planning Model, 2015.

Note: Emissions may not sum due to rounding.

Table [X]. Summary of CO2 and Other Air Pollutant Emission 

Reductions from the Base Case under Mass-based Illustrative Plan 

Approach

CO2

(million 

short tons)

SO2

(thousand 

short tons)

NOX 

(thousand 

short tons)

2020 Final Guidelines
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Base Case 2,155 1,311 1,333

Final Guidelines 2,073 1,257 1,272

Emissions Reductions 81 54 60

2025 Final Guidelines

Base Case 2,165 1,275 1,302

Final Guidelines 1,901 1,090 1,100

Emissions Reductions 265 185 203

2030 Final Guidelines

Base Case 2,227 1,314 1,293

Final Guidelines 1,814 1,034 1,015

Emissions Reductions 413 280 278

[PLACEHOLDER: IMPACTS TO BE BASED ON ANALYSIS FOR 111D FINAL 

RULE]

Source: Integrated Planning Model, 2015.

Note: Emissions may not sum due to rounding.

The reductions in Tables [X] and [X] do not account for 

reductions in hazardous air pollutants (HAPs) that may occur as 

a result of this rule. For instance, the fine particulate 

reductions presented above do not reflect all of the reductions 

in many heavy metal particulates.

C. What are the Energy Impacts? 

The final guidelines have important energy market 

implications. Table [X] presents a variety of important energy 

market impacts for 2020, 2025, and 2030 under both the ratebased and mass-based illustrative plan approaches. 

Table [X]. Summary Table of Important Energy Market Impacts for 

Rate-based and Mass-based Illustrative Plan Approaches (Percent 
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Change from Base Case)

Rate-Based Mass-Based

2020 2025 2030 2020 2025 2030

Retail electricity 

prices

3% 1% 1% 3% 2% 0%

Price of coal at 

minemouth -1% -5% -4% -1% -5% -3%

Coal production for 

power sector use -5% -14% -25% -7% -17% -24%

Price of natural gas 

delivered to power 

sector

5% -8% 2% 4% -3% -2%

Natural gas use for 

electricity generation

3% -1% -1% 5% 0% -4%

[PLACEHOLDER: IMPACTS TO BE BASED ON ANALYSIS FOR 111D FINAL 

RULE]

These figures reflect the EPA’s illustrative modeling that 

presumes policies that lead to generation shifts and growing use 

of demand-side energy efficiency and renewable electricity 

generation out to 2029. If states make different policy choices, 

impacts could be different. For instance, if states implement 

renewable and/or demand-side energy efficiency policies on a 

more aggressive time-frame, impacts on natural gas and 

electricity prices would likely be less. Implementation of other 

measures not included in the BSER calculation or compliance 
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modeling, such as nuclear uprates, transmission system 

improvements, use of energy storage technologies or retrofit 

CCS, could also mitigate gas price and/or electricity price 

impacts.

Energy market impacts from the guidelines are discussed 

more extensively in the RIA found in the docket for this 

rulemaking. 

D. What are the Compliance Costs?

[PLACEHOLDER: IMPACTS TO BE BASED ON ANALYSIS FOR 111D FINAL 

RULE]

The compliance costs of this final action are represented 

in this analysis as the change in electric power generation 

costs between the base case and the final rule in which states 

pursue a distinct set of strategies beyond the strategies taken 

in the base case to meet the terms of the final guidelines. The 

compliance costs estimates include cost estimates for demandside energy efficiency. The compliance assumptions – and,

therefore, the projected compliance costs - set forth in this 

analysis are illustrative in nature and do not represent the 

full suite of compliance flexibilities states may ultimately 

pursue. The illustrative analysis is designed to reflect, to the 

extent possible, the scope and the nature of the final 

guidelines. However, there is considerable uncertainty with 
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regards to the precise measures that states will adopt to meet 

the final requirements, because there are considerable 

flexibilities afforded to the states in developing their state 

plans.

The incremental cost is the projected additional cost of 

complying with the guidelines in the year analyzed and includes 

the amortized cost of capital investment, needed new capacity, 

shifts between or amongst various fuels, deployment of demandside energy efficiency 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 approach for final emission guidelines to be 

$2.5 billion in 2020, $1.0 billion in 2025 and $8.4 billion in 

2030, including the costs associated with monitoring, reporting, 

and recordkeeping (MR&R).127 The EPA estimates the annual 

incremental compliance cost for the mass-based approach for 

final emission guidelines to be $1.4 billion in 2020, $3.0 

billion in 2025 and $5.1 billion in 2030, including the costs 

associated with MR&R. 

 

127 The MR&R costs estimates are $65 million in 2020, $15 million 

in 2025 and $15 million in 2030 and are assumed to be the same 

for both rate-based and mass-based illustrative plan approaches.
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More detailed cost estimates are available in the RIA 

included in the rulemaking docket. 

E. What are the Economic and Employment Impacts?

[PLACEHOLDER: IMPACTS TO BE BASED ON ANALYSIS FOR 111D FINAL 

RULE]

The final standards are projected to result in certain 

changes to power system operation as a compliance with the 

standards. See Table [X] above for a variety of important energy 

market impacts for 2020, 2025, and 2030 under both the ratebased and mass-based illustrative plan approaches.

It is important to note that the EPA’s modeling does not 

necessarily account for all of the factors that may influence 

business decisions regarding future coal-fired capacity. Many 

power companies already factor a potential financial liability 

associated with carbon emissions into their long term capacity 

planning that would further influence business decisions to 

replace these aging assets with modern, and significantly 

cleaner, generation.

The compliance modeling done to support the final rule

assumes that overall electric demand will decrease as states 

ramp up programs that result in lower overall demand. Demandside energy efficiency levels are expected to increase such that 

they achieve about a 7.8 percent reduction on overall 
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electricity demand levels in 2030 under the final guidelines.

Changes in price or demand for electricity, natural gas, 

and coal can impact markets for goods and services produced by 

sectors that use these energy inputs in the production process 

or supply those sectors. Changes in the cost of production may 

result in changes in prices, quantities produced, and 

profitability of affected firms. The EPA recognizes that these 

guidelines provide significant flexibilities and states 

implementing the guidelines may choose to mitigate impacts to 

some markets outside the utility power sector. Similarly, demand 

for new generation or demand-side energy efficiency as a result 

of states implementing the guidelines can result in shifts in 

production and profitability for firms that supply those goods 

and services.

Executive Order 13563 directs federal agencies to consider 

the effect of regulations on job creation and employment. 

According to the Executive Order, “our regulatory system must 

protect public health, welfare, safety, and our environment 

while promoting economic growth, innovation, competitiveness, 

and job creation. It must be based on the best available 

science.” (Executive Order 13563, 2011) Although standard 

benefit-cost analyses have not typically included a separate 

analysis of regulation-induced employment impacts, we typically 
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conduct employment analyses. During the current economic 

recovery, employment impacts are of particular concern and 

questions may arise about their existence and magnitude. 

States have the responsibility and flexibility to implement 

policies and practices for compliance with the final guidelines. 

Quantifying the associated employment impacts is complicated 

by the wide range of approaches that states may use. As such, 

the EPA’s employment analysis includes projected employment 

impacts associated with illustrative plan approaches for these 

guidelines for the electric power industry, coal and natural gas 

production, and demand-side energy efficiency activities. These 

projections are derived, in part, from a detailed model of the 

utility power sector used for this regulatory analysis, and U.S 

government data on employment and labor productivity. In the 

electricity, coal, and natural gas sectors, the EPA estimates 

that these guidelines could result in a net decrease of 

approximately 25,000 job-years in 2025 for the final guidelines 

under the rate-based illustrative plan approach and 

approximately 26,000 job-years in 2025 under the mass-based 

approach. For 2030, the estimates of the net decrease in jobyears 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 
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demand-side energy efficiency programs. Employment impacts from 

demand-side energy efficiency programs in 2030 could range from 

approximately 52,000 to 83,000 jobs under the final guidelines. 

By its nature, demand-side energy efficiency reduces 

overall demand for electric power. The EPA recognizes as more 

efficiency is built into the U.S. power system over time, lower 

fuel requirements may lead to fewer jobs in the coal and natural 

gas extraction sectors, as well as in fossil-fuel fired EGU 

construction and operation than would otherwise have been 

expected. The EPA also recognizes the fact that, in many cases, 

employment gains and losses that might be attributable to this 

rule would be expected to affect different sets of people.

Moreover, workers who lose jobs in these sectors may find 

employment elsewhere just as workers employed in new jobs in 

these sectors may have been previously employed elsewhere. 

Therefore, the employment estimates reported in these sectors 

may include workers previously employed elsewhere. This analysis 

also does not capture potential economy-wide impacts due to 

changes in prices (of fuel, electricity, labor, for example) or 

other factors such as improved labor productivity and reduced 

health care expenditures resulting from cleaner air. For these 

reasons, the numbers reported here should not be interpreted as 

a net national employment impact. 
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F. What are the Benefits of the Proposed Action?

Implementing the final standards will generate benefits by

reducing emissions of CO2 and criteria pollutant precursors, 

including SO2, NOX, and directly emitted particles. SO2 and NOX

are precursors to PM2.5 (particles smaller than 2.5 microns), and 

NOX is a precursor to ozone. The estimated benefits associated 

with these emission reductions are beyond those achieved by 

previous EPA rulemakings including the Mercury and Air Toxics 

Standards rule. The health and welfare benefits from reducing 

air pollution are considered co-benefits for these standards. 

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 approach to be $3.5 to $4.6 billion 

in 2020, $18 to $28 billion in 2025, and $34 to $54 billion in 

2030 (3 percent discount rate, 2011$). Total combined climate 

benefits and health co-benefits for the mass-based 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 
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benefits estimated for this rule at all discount rates is 

provided in Tables [X] through [X] of this preamble.

Table [&&&]. Summary of the Monetized Global Climate Benefits 

for the Final Guidelines (billions of 2011$)a

Discount Rate 

(Statistic)

Monetized Climate Benefits 

YEAR 2020 2025 2030

Rate-based 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 Approach

CO2 

Reductions 

(million 

short tons)

81 265 413

5 percent (average 

SC-CO2)

$0.94 $3.6 $6.4

3 percent (average 

SC-CO2)

$3.3 $12 $20
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2.5 percent 

(average SC-CO2)

$4.9 $17 $29

3 percent (95th

percentile SC-CO2)

$9.7 $35 $60

a Climate benefit estimates reflect impacts from CO2 emission 

changes in the analysis years presented in the table and do not 

account for changes in non-CO2 GHG emissions. These estimates are 

based on the global social cost of carbon (SC-CO2) estimates for 

the analysis years and are rounded to two significant figures. 

Table [X]. Summary of the Monetized Health Co-Benefits in the 

U.S. for the Final Guidelines, Rate-based 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)

Final Guidelines, Rate-based Approach, 2020

PM2.5 precursors b

SO2 14

$0.44 to 

$0.99

$0.39 to 

$0.89

NOX 50

$0.14 to 

$0.33

$0.13 to 

$0.30

Ozone precursor c

NOX (ozone season only) 19

$0.12 to 

$0.52

$0.12 to 

$0.52

Total Monetized Health Co-benefits $0.70 to 

$1.8

$0.64 to 

$1.7
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Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$3.5 to $4.6 $3.5 to $4.5

Final Guidelines, Rate-based 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

Final Guidelines, Rate-based Approach, 2030

PM2.5 precursors b

SO2 318 $12 to $28 $11 to $25

NOX 282

$1.0 to $2.3

$0.93 to 

$2.1

Ozone precursor c

NOX (ozone season 

only)

118

$0.86 to 

$3.7

$0.86 to 

$3.7

Total Monetized Health Co-benefits $14 to $34 $13 to $31

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$34 to $54 $33 to $51

a All estimates are rounded to two significant figures, so 

estimates may not sum. It is important to note that the 

monetized co-benefits do not include reduced health effects from 

direct exposure to SO2, direct exposure to NO2, exposure to 
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mercury, ecosystem effects or visibility impairment. Air 

pollution health co-benefits are estimated using regional 

benefit-per-ton estimates for the contiguous U.S.

b The monetized PM2.5 co-benefits reflect the human health 

benefits associated with reducing exposure to PM2.5 through 

reductions of PM2.5 precursors, such as SO2 and NOX. The cobenefits do not include the benefits of reductions in directly 

emitted PM2.5. These additional benefits would increase overall 

benefits by a few percent based on the analyses conducted for 

the proposed rule. 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 
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considering the full range of social cost of carbon values. We 

provide combined climate and health estimates based on 

additional discount rates in the RIA.

Table [X]. Summary of the Monetized Health Co-Benefits in the 

U.S. for the Final Guidelines, Mass-based 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)

Final Guidelines, Mass-based 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

Final Guidelines, Mass-based 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
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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

Final Guidelines, Mass-based Approach, 2030

PM2.5 precursors b

SO2 280 $10 to $23 $9.0 to $20

NOX 278

$0.87 to 

$2.0

$0.79 to 

$1.8

Ozone precursor c

NOX (ozone season 

only)

121

$0.82 to 

$3.5

$0.82 to 

$3.5

Total Monetized Health Co-benefits $12 to $28 $11 to $26

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$32 to $48 $31 to $46

[PLACEHOLDER: IMPACTS TO BE BASED ON ANALYSIS FOR 111D 

FINAL RULE]

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 
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emitted PM2.5. These additional benefits would increase overall 

benefits by a few percent based on the analyses conducted for 

the proposed rule. PM co-benefits are shown as a range 

reflecting the use of two concentration-response functions, with 

the lower end of the range based on a function from Krewski et 

al. (2009) and the upper end based on a function from Lepeule et 

al. (2012). These models assume that all fine particles, 

regardless of their chemical composition, are equally potent in 

causing premature mortality because the scientific evidence is 

not yet sufficient to allow differentiation of effect estimates 

by particle type.

c The monetized ozone co-benefits reflect the human health 

benefits associated with reducing exposure to ozone through 

reductions of NOX during the ozone season. Ozone co-benefits are 

shown as a range reflecting the use of several different 

concentration-response functions, with the lower end of the 

range based on a function from Bell, et al. (2004) and the upper 

end based on a function from Levy, et al. (2005). Ozone cobenefits occur in the analysis year, so they are the same for 

all discount rates.

d We estimate climate benefits associated with four different 

values of a one ton CO2 reduction (model average at 2.5 percent 

discount rate, 3 percent, and 5 percent; 95th percentile at 3 

percent). Referred to as the social cost of carbon, each value 

increases over time. For the purposes of this table, we show the 

benefits associated with the model average at 3 percent discount 

rate, however we emphasize the importance and value of 

considering the full range of social cost of carbon values. We 

provide combined climate and health estimates based on 

additional discount rates in the RIA.

The EPA has used the social cost of carbon (SC-CO2) 

estimates presented in the Technical Support Document: Technical 
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Update of the Social Cost of Carbon for Regulatory Impact

Analysis Under Executive Order 12866 (May 2013, Revised June 

2015) (“current TSD”) to analyze CO2 climate impacts of this 

rulemaking.128 We refer to these estimates, which were developed 

by the U.S. government, as “SC-CO2 estimates.” The SC-CO2 is a 

metric that estimates the monetary value of impacts associated 

with marginal changes in CO2 emissions in a given year. It 

includes a wide range of anticipated climate impacts, such as 

net changes in agricultural productivity and human health, 

property damage from increased flood risk, and changes in energy 

system costs, such as reduced costs for heating and increased 

costs for air conditioning. It is typically used to assess the 

avoided damages as a result of regulatory actions (i.e., 

 

128 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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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)129 provides a complete discussion of 

the methods used to develop these estimates and the current TSD 

 

129 Docket ID EPA-HQ-OAR-2009-0472-114577, Technical Support 

Document: Social Cost of Carbon for Regulatory Impact Analysis 

Under Executive Order 12866, Interagency Working Group on Social 

Cost of Carbon, with participation by the Council of Economic 

Advisers, Council on Environmental Quality, Department of 

Agriculture, Department of Commerce, Department of Energy, 

Department of Transportation, Environmental Protection Agency, 

National Economic Council, Office of Energy and Climate Change, 

Office of Management and Budget, Office of Science and 

Technology Policy, and Department of Treasury (February 2010). 

Also available at: 

http://www.whitehouse.gov/sites/default/files/omb/inforeg/foragencies/Social-Cost-of-Carbon-for-RIA.pdf.
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presents and discusses the 2013 update (including two recent 

minor corrections to the estimates).130

The EPA received numerous comments on the SC-CO2 estimates 

as part of this rulemaking. The comments covered a wide range of 

topics including the technical details of the modeling conducted 

to develop the SC-CO2 estimates, the aggregation and presentation 

of the SC-CO2 estimates, and the process by which the SC-CO2

estimates were derived. Many but not all commenters were 

supportive of the SC-CO2 and its application to this rulemaking. 

Commenters also provided constructive recommendations for 

potential opportunities to improve the SC-CO2 estimates in future 

updates. Many of these comments were similar to those that OMB’s 

Office of Information and Regulatory Affairs received in 

 

130 The current version of the TSD is available at: 

https://www.whitehouse.gov/sites/default/files/omb/inforeg/sccresponse-to-comments-final-july-2015.pdf, Docket ID EPA-HQ-OAR2013-0495, Technical Support Document: Technical Update of the 

Social Cost of Carbon for Regulatory Impact Analysis Under 

Executive Order 12866, Interagency Working Group on Social Cost 

of Carbon, with participation by Council of Economic Advisers, 

Council on Environmental Quality, Department of Agriculture, 

Department of Commerce, Department of Energy, Department of 

Transportation, Domestic Policy Council, Environmental 

Protection Agency, National Economic Council, Office of 

Management and Budget, Office of Science and Technology Policy, 

and Department of Treasury (May 2013, Revised July 2015).
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response to a separate 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.131 With the release of the response 

to comments, the IWG announced plans to obtain expert 

independent advice from the National Academies of Sciences, 

Engineering, and Medicine (Academies) to ensure that the SC-CO2

estimates continue to reflect the best available scientific and 

economic information on climate change. The Academies review 

will be informed by the public comments received and focus on 

the technical merits and challenges of potential approaches to 

improving the SC-CO2 estimates in future updates. See the EPA 

Response to Comments document for the complete response to 

comments received on SC-CO2 as part of this rulemaking. 

Concurrent with OMB’s publication of the response to 

comments on SC-CO2 and announcement of the Academies process, OMB 

posted a revised TSD that includes two minor technical 

corrections to the current estimates. One technical correction 

addressed an inadvertent omission of climate change damages in 

 

131 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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the last year of analysis (2300) in one model and the second 

addressed a minor indexing error in another model. On average 

the revised SC-CO2 estimates are one dollar less than the mean 

SC-CO2 estimates reported in the November 2013 revision to the 

May 2013 TSD. The change in the estimates associated with the 

95th percentile estimates when using a 3 percent discount rate 

is slightly larger, as those estimates are heavily influenced by 

the results from the model that was affected by the indexing 

error.

The EPA, as a member of the IWG on the SC-CO2, has 

carefully examined and evaluated the minor technical corrections 

in the revised TSD and the public comments submitted to OMB’s 

separate SC-CO2 comment process. Additionally, the EPA has 

carefully examined and evaluated all comments received regarding 

the SC-CO2 through this rulemaking 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 

$120 per short ton of CO2 emissions in the year 2020 (2011$).132

 

132 The current version of the TSD is available at: 

https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-
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The first three values are based on the average SC-CO2 from the 

three IAMs, at discount rates of 5, 3, and 2.5 percent, 

respectively. The SC-CO2 value at several discount rates are 

included because the literature shows that the SC-CO2 is quite 

sensitive to assumptions about the discount rate, and because no 

consensus exists on the appropriate rate to use in an 

intergenerational context (where costs and benefits are incurred 

by different generations). The fourth value is the 95th

percentile of the SC-CO2 from all three models at a 3 percent 

discount rate. It is included to represent higher-than-expected 

impacts from temperature change further out in the tails of the 

SC-CO2 distribution (representing less likely, but potentially 

catastrophic, outcomes).

There are limitations in the estimates of the benefits from 

the final emission guidelines, 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 

 

tsd-final-july-2015.pdf. The 2010 and 2013 TSDs present SC-CO2 in 

2007$ per metric ton. The estimates were adjusted to (1) short 

tons for using conversion factor 0.90718474 and (2) 2011$ using 

GDP Implicit Price Deflator, http://www.gpo.gov/fdsys/pkg/ECONI2013-02/pdf/ECONI-2013-02-Pg3.pdf.
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treatment of adaptation and technological change, uncertainty in 

the extrapolation of damages to high temperatures, and 

assumptions regarding risk aversion. Currently, IAMs do not 

assign value to all of the important impacts of CO2 recognized in 

the literature, such as ocean acidification or potential tipping 

points, for various reasons, including the inherent difficulties 

in valuing non-market impacts and the fact that the science 

incorporated into these models understandably lags behind the 

most recent research. Nonetheless, these estimates and the 

discussion of their limitations represent the best available 

information about the social benefits of CO2 emission reductions 

to inform the benefit-cost analysis. As previously noted, the 

IWG plans to seek independent expert advice on technical 

opportunities to improve the SC-CO2 estimates from the Academies. 

The Academies process will help to ensure that the SC-CO2

estimates used by the federal government continue to reflect the 

best available science and methodologies. Additional details are 

provided in the TSDs.

The health co-benefits estimates represent the total 

monetized human health benefits for populations exposed to 

reduced PM2.5 and ozone resulting from emission reductions from 

the illustrative compliance strategy for the final standards. 

Unlike the global SC-CO2 estimates, the air pollution health co-
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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 standards to convert precursor emissions 

into changes in ambient PM2.5 and ozone concentrations. We then 

used these air quality modeling results in BenMAP133 to calculate

average regional benefit-per-ton estimates using the health 

impact assumptions used in the PM NAAQS RIA134 and Ozone NAAQS 

RIAs.135,136 The three regions were the Eastern U.S., Western U.S., 

 

133 http://www.epa.gov/airquality/benmap/index.html

134 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>.

135 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>.

136 U.S. Environmental Protection Agency (U.S. EPA). 2010. Section 

3: Re-analysis of the Benefits of Attaining Alternative Ozone 
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and California. To calculate the co-benefits for the final

standards, we multiplied the regional benefit-per-ton estimates 

generated from modeling of the proposed standards by the 

corresponding regional emission reductions for the final 

standards.137 All benefit-per-ton estimates reflect the 

geographic distribution of the modeled emissions for the 

proposed standards, which may not exactly match the emission 

reductions in this final 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 RIA. 

PM benefit-per-ton values are generated using two 

 

Standards to Incorporate Current Methods. Available at: 

<http://www.epa.gov/ttnecas1/regdata/RIAs/s3-

supplemental_analysis-updated_benefits11-5.09.pdf>. 

137 U.S. Environmental Protection Agency. 2013. Technical support 

document: Estimating the benefit per ton of reducing PM2.5

precursors from 17 sectors. Research Triangle Park, NC: Office 

of Air and Radiation, Office of Air Quality Planning and 

Standards, January. Available at: 

<http://www.epa.gov/airquality/benmap/models/Source_Apportionmen

t_BPT_TSD_1_31_13.pdf>.
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concentration-response functions, Krewski et al. (2009) 138 and 

Lepeule et al. (2012) 139. These models assume that all fine 

particles, regardless of their chemical composition, are equally 

potent in causing premature mortality because the scientific 

evidence is not yet sufficient to allow differentiation of 

effect estimates by particle type. Even though we assume that 

all fine particles have equivalent health effects, the benefitper-ton estimates vary between PM2.5 precursors depending on the 

location and magnitude of their impact on PM2.5 concentrations, 

which drive population exposure. 

It is important to note that the magnitude of the PM2.5 and 

ozone co-benefits is largely driven by the concentration 

response functions for premature mortality and the value of a 

statistical life used to value reductions in premature 

mortality. For PM2.5, we use two key empirical studies, one based 

on the American Cancer Society cohort study (Krewski et al, 

2009) and one based on the extended Six Cities cohort study

 

138 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.

139 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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(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)140 as a characterization of uncertainty 

regarding the PM2.5-mortality relationship.

For the ozone co-benefits, we present the results as a range 

reflecting benefit-per-ton estimates which use several different 

concentration-response functions for mortality, with the lower 

end of the range based on a benefit-per-ton estimate using the

function from Bell et al. (2004)141 and the upper end based on a

benefit-per-ton estimate using the function from Levy et al. 

 

140 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.

141 Bell, M.L., et al. 2004. “Ozone and Short-Term Mortality in 

95 U.S. Urban Communities, 1987-2000.” Journal of the American 

Medical Association, 292(19), pp. 2372-8.
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(2005).142 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 EPA’s Integrated Science Assessment for 

Particulate Matter,143 which evaluated the substantial body of 

published scientific literature, reflecting thousands of 

epidemiology, toxicology, and clinical studies that documents 

the association between elevated PM2.5 concentrations and adverse 

health effects, including increased premature mortality. This 

assessment, which was twice reviewed by the EPA’s independent 

Science Advisory Board, concluded that the scientific literature 

consistently finds that a no-threshold model most adequately 

portrays the PM-mortality concentration-response relationship. 

In general, we are more confident in the magnitude of the 

 

142 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.

143 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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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,144 and thus, we are unable to estimate the percentage 

of premature mortality associated with this specific rule that 

is above the lowest measured PM2.5 levels (LML) for the two PM2.5

mortality epidemiology studies that form the basis for our 

analysis. As a surrogate measure of mortality impacts above the 

LML, we provide the percentage of the population exposed above 

the lowest measured PM2.5 level (LML) in each of the two studies, 

using the estimates of baseline projected PM2.5 from the air 

quality modeling for the proposed guidelines used to calculate 

the benefit-per-ton estimates for the EGU sector. Using the 

Krewski et al. (2009) study, 88 percent of the population is 

exposed to annual mean PM2.5 levels at or above the LML of 5.8 

micrograms per cubic meter (μg/m3). Using the Lepeule et al. 

(2012) study, 46 percent of the population is exposed above the 

 

144 In addition, site-specific emission reductions will depend 

upon how states implement the guidelines.
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LML of 8 μg/m3. It is important to note that baseline exposure is 

only one parameter in the health impact function, along with 

baseline incidence rates, population, and change in air quality. 

Every benefit analysis examining the potential effects of a 

change in environmental protection requirements is limited, to 

some extent, by data gaps, model capabilities (such as 

geographic coverage) and uncertainties in the underlying 

scientific and economic studies used to configure the benefit 

and cost models. Despite these uncertainties, we believe the air 

quality co-benefit analysis for this rule provides a reasonable 

indication of the expected health benefits of the air pollution 

emission reductions for the illustrative analysis of the final

standards under a set of reasonable assumptions. This analysis 

does not include the type of detailed uncertainty assessment 

found in the 2012 PM2.5 National Ambient Air Quality Standard 

(NAAQS) RIA (U.S. EPA, 2012) because we lack the necessary air 

quality input and monitoring data to conduct a complete benefits 

assessment. In addition, using a benefit-per-ton approach adds 

another important source of uncertainty to the benefits 

estimates. The 2012 PM2.5 NAAQS benefits analysis provides an 

indication of the sensitivity of our results to various 

assumptions. 

We note that the monetized co-benefits estimates shown here 
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do not include several important benefit categories, including 

exposure to SO2, NOX, and hazardous air pollutants (e.g., mercury 

and hydrogen chloride), as well as ecosystem effects and 

visibility impairment. Although we do not have sufficient 

information or modeling available to provide monetized estimates 

for this rule, we include a qualitative assessment of these 

unquantified benefits in the RIA for the final guidelines. In 

addition, in the RIA for the final standards, 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 

guidelines, the benefits from reductions in directly emitted 

PM2.5 were less than 10 percent of total monetized health cobenefits across all scenarios and years.

For more information on the benefits analysis, please refer 

to the RIA for this rule, which is available in the rulemaking 

docket.

IX. Community Considerations and Environmental Justice

Considerations

In this section we provide an overview of the actions that 

the agency is taking to help ensure that vulnerable communities 

are not disproportionately impacted by this rulemaking. 

As described in the Executive Summary, climate change is an 
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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 overburdenedvulnerable communities 

is provided in the Executive Order 12898 section XII.J of this 

preamble). While climate change is a global phenomenon, the 

adverse effects of climate change can be very localized, as 

impacts such as storms, flooding, droughts, and the like are 

experienced in individual communities. 

This rule will bring other important benefits to

communities across the nation. Vulnerable communities also often 

receive more than their fair share of conventional air 

pollution, with the attendant adverse health impacts.

The changes in electricity generation that will result from
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this rule will further benefit communities by reducing existing 

air pollution that directly contributes to adverse localized 

health effects. This benefitThese air quality improvements will 

be achieved through the rulemakingthis rule because the electric 

generating units 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.145 The EPA expects that the

reductions in utilization of higher-emitting units likely to 

occur during the implementation of federal plans will produce 

significant reductions in emissions of conventional pollutants, 

particularly in overburdened communities.those communities 

already overburdened by pollution, which are often low-income 

communities, communities of color, and indigenous communities. 

These reductions will have beneficial effects on air quality and 

public health both locally and regionally. Further, this 

rulemaking complements other actions already taken by the EPA to 

 

145 Six Common Air Pollutants. www.epa.gov/oaqps001/urbanair/
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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.

While the agency expects overall emission decreases as a 

result of this rulemaking, we recognize that certainsome EGUs 

may operate more frequently. To the extent that we project 

increases in utilization as a result of this rulemaking, we 

expect these increases to occur generally in lower-emitting NGCC 

units, which have minimal or no emissions of SO2 and HAP, lower 

emissions of particulate matter, and much lower emissions of NOx
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compared to higher-emitting steam units. We acknowledge the 

concerns that have been raised on this point, but also the 

difficulty in anticipating prior to plan implementation where 

those impacts might occur. As described below, the EPA intends 

to assess any emissionsconduct an assessment of whether and 

where emission increases that may result from plan

implementation and mitigate adverse impacts, if any, in 

overburdened communities.

In addition to the many positive anticipated health 

benefits of this rulemaking, it also will increase the use of 

clean energy and will encourage energy efficiency. These changes 

in the electricity generation system, which are already 

occurring, but may be accelerated by this program, are expected 

to have other positive benefits for communities. The electricity 

sector is, and will continue to be, investing more in RE and EE. 

The construction of renewable generation and the implementation 

of energy efficiency programs such as residential weatherization 

will bring investinvestment and employment opportunities to the 

communities where they take place. It is important to ensure 

that all communities share in these benefits. And while we 

estimate that the benefits of this program will greatly exceed 

its costs (as noted in the RIA for this rulemaking)), it is also 

important to ensure that to the extent that there are increases 
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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. InThis input has informed this 

proposedfinal rulemaking we address many ofand prompted the 

concernsEPA to consider other steps that were raised. One 

example is that commenters are concerned about the health, 

economic, and agency can take in the short and long term to 

assist states and stakeholders to consider environmental justice 

and impacts of climate change, but also want to ensure that the 

benefits of this rulemaking are shared fairly and that low 

incometo communities are not adversely affected by the increased 

costs of electricity. In this section, we respond to these 

concerns.in plan development and implementation. 

We are workingIt has also prompted us to work with our 

federal partners to make sure that communities have information 

on federal resources available to assist them. We describe these 

resources below, as well as resources that the EPA will be 

providing to assist communities in accessing EE/RE and financial 

assistance programs. 
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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 ana

proximity analysis for this proposed rulemaking that summarizes 

demographic data on the communities located near power plants, 

which we refer to as a proximity analysis.146 The EPA understands 

that, in order to prevent disproportionate,disproportionately 

high and adverse human health or environmental effects on these 

communities, both the agency and communities must have 

information on the communities living near facilities, including 

demographic data, and that accessing and using census data files 

requires expertise that some community groups may lack. 

Therefore, the EPA used census data from the American Community 

 

146 The proximity analysis was conducted using data that are used 

to update the EPA’s environmental justice mapping and screening 

tool, EJSCREEN).
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Survey (ACS) 2008-2012 to conduct a proximity analysis that can 

be used by communities as they engage with the agency throughout 

the comment period of this rulemaking. The analysis and its 

results are presented in the EJ Screening Report for the Clean 

Power Plan, which is located in the docket for this rulemaking 

at EPA-HQ-OAR-2015-0199.

The proximity analysis provides detailed demographic 

information on the communities located within a 3-mile radius of 

each affected power plant in the United States. 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 
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than national averages, there are differences between rural and 

urban power plants. There are many rural power plants that are 

located near small communities with high percentages of lowincome populations and lower percentages of communities of 

color. In urban areas, nearby communities tend to be both lowincome communities and communities of color. In light of this 

difference between rural and urban communities proximate to 

power plants and in order to adequately capture both the lowincome and minority aspects central to environmental justice 

considerations, we will use the termterms “vulnerable” or

“overburdened” when referring to these communities. Our intent 

is for this termthese terms to be understood in an expansive 

sense, in order to capture the full scope of communities, 

including tribalindigenous communities most often located in 

rural areas, whichthat are central to our environmental 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 

guidelinesstandards for existing affected fossil fuel-fired 

power plants. The EPA also believes that the information 
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provided in the proximity analysis will promote engagement 

between overburdenedvulnerable communities and the agency 

throughout the rulemaking process. In addition to providing the 

proximity analysis in the docket of this rulemaking, the EPA 

will make it publicly available on its EPA Community Climate 

Protection Portal of the Clean Power Plan (CPP) Communities 

Portal that will be linked to this rulemaking’s website 

(www.epa.gov/cleanpowerplanWebsite.). 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 overburdenedvulnerable communities

throughout the outreach process for the Clean Power Plan that it 

is imperative for overburdened communities to have an 

understanding of how rulemakings that target climate change 

work. They expressed a desire to know how these 

rulemakingsprograms may benefit their communities and what the 

potential adverse impacts of the rulemakingrules may be on their 

communities. It is importantWe intend to the EPA that the agency 

provides overburdenedprovide communities with the information 

that they need to engage with the agency throughout the comment 
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period. 

We have received feedback from communities that public 

hearings, webinars and in-person meetings are the most effective 

ways to engage with them and to provide them with the 

information that they need to understand the rulemaking process. 

Therefore, for this rulemaking, in addition to conducting public 

hearings for all members of the American public (please see the 

dates section for information on the upcoming public hearings), 

the agency will hold a national webinar for affected communities 

in the early stages of the comment period. The goal of this 

webinar will be to walk overburdened communities through the 

highlights of the preamble, so they have an understanding of how 

the rulemaking may potentially impactaffect their 

communitycommunities and they will have the contextual 

information they need to actively engage with the agency 

throughout the comment period. 

Additionally, because we received positive feedback on the

effectiveness of the face-to-face meetings conducted on the 

regional level, each region will be offering an outreach 

meeting(s) for overburdened communities. The goal of these 

meetings is to build a level of understanding on this rulemaking 

to enable overburdenedvulnerable communities to actively engage 

with the agency throughout the comment period. Furthermore, we 
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will follow up on common issues raised during the outreach 

meetings with national conference calls, specifically targeted 

for overburdenedvulnerable communities.

C. Providing Communities with Access to Additional Resources

In section V.D. of this preamble we outline that we are 

seeking comment on whether a portion of this set-aside should be 

targeted to RE projects that benefit low-income communities. 

Furthermore, the EPA is seeking comment on how an low-income

community should be defined as eligible under this set-aside. We 

also seek comment on how much of the set-aside should be 

designated as targeted at over-burdened communities. We also 

request comment on whether the methods of approval and 

distribution of allowances to projects that benefit low-income

communities should differ, and if so, in what manner, from the 

methods that are proposed to apply to other RE projects.

As discussed below, there are also many federal programs 

that can help overburdenedlow-income populations access the 

benefits of renewable energy, energy efficiency, and the 

economic benefits of a cleaner energy economy. 

In the coming months, the EPA will continue to provide 

information and resources for overburdenedlow-income communities 

on existing federal, state, local, and other financial 

assistance programs to encourage EE/RE opportunities that are 
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already available to communities. For example the EPA will also

provide a catalog of current or recent state and local programs 

that have successfully helped communities adopt EE/RE measures. 

The goal of these resources is to help overburdenedvulnerable

communities gain the benefits of this rulemaking. The use of 

these RE/EE tools can also overburdenedhelp low-income

households reduce their electricity consumption and bills. 

Additionally, as part of the resources that we will be 

providing overburdenedlow-income communities, the EPA will 

provide information on the White House’s Adminstration’s 

Partnerships for Opportunity and Workforce and Economic 

Revitalization (POWER Initiative) Initative and other programs 

that specifically target economic development assistance to 

communities affected by changes in the coal industry and the 

utility power sector.147

D. Federal Programs and Resources Available to Communities

A. Federal Programs and Resources Available to Communities

Federal agencies have a history of bringing energy 

efficiency and renewable energy to low-income communities. Some 

examples of federal programs that offer resources for low-income communities. Earlier 

this summer, the Administration announced a new initiative to 

 

147 www.epa.gov/power/.
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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 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 energy 

efficiency 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 
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programs and resources available to improve energy efficiency 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 Housing and Urban Development’s goal (under the 

President’s Climate Action Plan) of installing 100 megawatts of RE 

across federally subsidized housing by 2020, the Department of 

Agriculture’s Energy Efficiency and Conservation Loan Program, and 

the Environmental Protection Agency’s RE-Powering America’s Land 

Initiative. The EPA will be working with these federal partners 

and others to ensure that overburdened communities have access to 

information on these programs and their resourcesAgriculture’s 

Energy Efficiency and Conservation Loan Program, High Cost Energy 

Grant Program, and the Rural Housing Service’s Multi-Family 

Housing Program.

HUD supports energy efficiency improvements and the 

deployment of renewable energy on affordable housing through its

Energy Efficient Mortgage Program, Multifamily Property Assessed 

Clean Energy Pilot with the State of California, PowerSaver 

Program, and the use of Section 108 Community Development Block 

Grants. The Department of Treasury provides several tax credits 

to support renewable energy development and energy efficiency in 
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low-income communities, including the New Markets Tax Credit 

Program and the Low-Income Housing Tax Credit. The EPA’s REPowering America’s Land Initiative promotes the reuse of 

potentially contaminated lands, landfills and mine sites – many 

of which are in low-income communities – for 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 energy efficiency 

programs throughout the country that leverage ENERGY STAR to 

deliver broad consumer energy-saving benefits, of particular 

value to low-income households who can least afford high energy 

bills. ENERGY STAR also works with houses of worship to reduce 

energy costs – savings that can then be repurposed to their 

community mission, including programs and assistance to 

residents in low-income communities. The EPA will be working 

with these federal partners and others to ensure that states and 

vulnerable communities have access to information on these 

programs and their resources.

The federal government also has a number of programs to 

expand employment opportunities in the energy sector, including 

for underserved populations. Examples of these include HUD, DOE, 
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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.148

In the Cross-State Air Pollution Rule the EPA used its authority 

to reduce emissions that significantly contribute to downwind 

exposures. The RIA for the final Cross-State Air Pollution Rule 

anticipates substantial health benefits for the population 

across a wide region. Similarly, the EPA believes that, like the 

Cross-State Air Pollution Rule, this rulemaking will result in 

significant health benefits because it will reduce co-pollutant 

 

148 76 FR 48348.
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emissions of SO2 and NOx on a regional and national basis.149

Thus, localized increases in NOx emissions may well be more than 

offset by NOx decreases elsewhere in the region that produce a 

net improvement in ozone and particulate concentrations across 

the area.

Another effect of the final CO2 emission guidelinesstandards

for affected existing fossil fuel-fired EGUs may be increased 

utilization of other, unmodified EGUs - in particular, high 

efficiency gas-fired EGUs - with relatively low GHG emissions 

per unit of electrical output. These plants may operate more 

hours during the year and could emit pollutants, including 

pollutants whose environmental effects would be localized /and

or regional rather than global as is the case with GHG 

emissions. Changes in utilization already occur in response to 

energy demands and evolving energy sources, but the final CO2 

emission guidelinesstandards for affected existing fossil fuelfired EGUs can be expected to cause more such changes. Increased 

utilization of solid fossil fuel-fired units generally would not 

increase peak concentrations of PM2.5, NOx, or ozone around such 

EGUs to levels higher than those that are already occurring 

because peak hourly or daily emissions generally would not 

 

149 76 FR 48347.
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change; however, increased utilization may make periods of 

relatively high concentrations more frequent. It should be noted 

that the gas-fired sources likely to be dispatched more 

frequently have very low emissions of primary PM, SO2, and HAP 

per unit of electrical output and that they must continue to 

comply with other CAA requirements that directly address the 

conventional pollutants, including federal emission standards, 

rules included in state implementation 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 gas-fired EGUs, the EPA found that regulation of HAP 

emissions “is not appropriate or necessary because the impacts 

due to HAP emissions from such units are negligible based on the 

results of the study documented in the utility RTC.”150 Because 

gas-fired EGUs emit essentially no mercury, increased 

utilization will not increase methyl mercury concentrations in 

water bodies near these affected EGUs. In studies done by 

DOE/NETL comparing cost and performance of coal-and NGCC-fired 

generation, they assumed SO2, NOx, PM (and Hg) emissions to be 

“negligible.” Their studies predict NOx emissions from a NGCC 

 

150 65 FR 79831.
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unit to be approximately 10 times lower than a subcritical or 

supercritical coal-fired boiler.151 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 

communitiesby disproportionate environmental harms and risks. 

The EPA will conduct its own assessment during the 

implementation phase of this rulemaking to determine whether the 

implementation of federal plans and other air quality rules are, 

in fact, reducing emissions and improving air quality in all 

areas and, or whether there are localized air quality impacts 

that need to be addressed under the Clean other CAA authorities.

The EPA will provide trainings for communities on resources 

that they can use to assess localized impacts, especially 

effects of co-pollutants, of plans on their communities. This 

 

151 “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. EPAThe EPA’s Continued Engagement 

The EPA is committed to helping ensure that this action 

will not have disproportionate adverse human health or 

environmental effects on overburdenedvulnerable communities. 

Throughout the implementation phase of this rulemaking, the 

agency will continue to provide trainings and resources to 

assist overburdened communities and as they engage with the 

agency. The EPA, through its outreach efforts during the comment 

period, will continue to solicit feedback from overburdened 

communities on what they would like additional trainings and 

resources on.

As described above, the EPA will assess the impacts of this 

rulemaking during its implementation. The EPA will house this 

assessment, along with the proximity analysis and other 
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information generated throughout the implementation process, on 

its EPA Community Climate ProtectionClean Power Plan (CPP) 

Communities Portal that will be linked to this rulemaking’s 

website (www.epa.gov/cleanpowerplan). In addition, the EPA has 

expanded its set of resources that are being developed to help 

overburdened communities understand the breadth of policy 

options and programs that have successfully brought EE/RE to 

overburdenedlow-income communities. The EPA is 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.152 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 

 

152 Guidance on Considering Environmental Justice During the 

Development of Regulatory Actions. 

www.epa.gov/environmentaljustice/resources/policy/consideringej-in-rulemaking-guide-final.pdf. May 2015.
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from communities, are provided in the response to comments 

documents located in the docket for this rulemaking.

In summary, the EPA in this proposed rulemaking has designed 

an integrative approach that helps to ensure that vulnerable 

communities are not disproportionately impacted by this rule. The 

proximity analysis that the agency has conducted is a central 

component of this approach. Not only is the proximity analysis a 

useful tool to help identify communities that may be impacted by 

this rulemaking; it will also help communities as they engage with 

the EPA throughout the comment period. It will help the EPA as we 

help low-income communities access EE/RE and financial assistance 

programs. Finally, in order to continue to ensure that overburdened 

communities are not disproportionately impacted by this rule, the 

EPA will be conducting an assessment during the implementation 

phase of the effects of this and other rules on air quality. 

X. Statutory and Executive Order Reviews

Additional information about these statutes and Executive 

Orders can be found at www2.epa.gov/laws-regulations/laws-andexecutive-ordersorders..
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A. Executive Order 12866: Regulatory Planning and Review and 

Executive Order 13563: Improving Regulation and Regulatory 

Review 

[&&&based on preliminary analysis]

This final action is an economically significant regulatory 

action that was submitted to the Office of Management and Budget 

(OMB) for review. Any changes made in response to OMB 

recommendations have been documented in the docket. The EPA 

prepared an analysis of the potential costs and benefits 

associated with this action. This analysis, “[&&&insert title of 

document],”This analysis, which is contained in the “Regulatory 

Impact Analysis for Clean Power Plan Final Rule” (EPA-452/R-15-

003, July 2015), is available in the docket. and is briefly 

summarized in section XI of this preamble. 

Consistent with EOExecutive Order 12866 and EOExecutive 

Order 13563, the EPA estimated the costs and benefits for 

illustrative compliance approaches of implementing the model 

tradingguidelines. The final rule establishes: 1) carbon dioxide 

(CO2) emission performance rates for two source categories of 

existing fossil fuel-fired EGUs, fossil fuel-fired electric 

utility steam generating units and federalstationary combustion 

turbines, and 2) guidelines for the development, submittal and 

implementation of state plans that implement the CO2 emission 
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performance rates. Actions taken to comply with the guidelines 

will also reduce the emissions of directly-emitted PM2.5, SO2 and 

NOX. The benefits associated with these PM2.5, SO2 and NOX

reductions are referred to as co-benefits, as these reductions 

are not the primary objective of this rule.

The EPA has used the social cost of carbon estimates 

presented in the Technical Support Document: Technical 

Update of the Social Cost of Carbon for Regulatory Impact 

Analysis Under Executive Order 12866 (May 2013, Revised 

July 2015) (“current TSD”) to analyze CO2 climate impacts of 

this rulemaking. We refer to these estimates, which were 

developed by the U.S. government, as “SC-CO2 estimates.” The 

SC-CO2 is an estimate of the monetary value of impacts 

associated with a marginal change in CO2 emissions in a 

given year. The four SC-CO2 estimates are associated with 

different discount rates (model average at 2.5 percent 

discount rate, 3 percent, and 5 percent; 95th percentile at 

3 percent), and each increases over time. In this summary, 

the EPA provides the estimate of climate benefits 

associated with the SC-CO2 value deemed to be central in the 

current TSD: the model average at 3 percent discount rate. 

In the final emission guidelines, the EPA has translated 

the source category-specific CO2 emission performance rates into 
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equivalent state-level rate-based and mass-based CO2 goals in 

order to maximize the range of choices that states will have in 

developing their plans. Because of the range of choices 

available to states and the lack of a priori knowledge about the 

specific choices states will make in response to the final 

goals, the Regulatory Impact Analysis (RIA) for this rule 

analyzed two implementation scenarios designed to achieve these 

goals, which we term the “rate-based” illustrative plan approach 

and the “mass-based” illustrative plan approach.

It is very important to note that the differences between 

the analytical results for the rate-based and mass-based 

illustrative plan approaches presented in the RIA may not be 

indicative of likely differences between the approaches if 

implemented by states and affected EGUs in response to the final 

guidelines. Rather, the two sets of analyses are intended to 

illustrate two different approaches to accomplish the emission 

performance rates finalized in the Clean Power Plan Final Rule. 

In other words, if one approach performs differently than the 

other on a given metric during a given time period, this does 

not imply this will apply in all instances in all time periods 

in all places.

The EPA estimates that, in 2020, the final guidelines 

will yield monetized climate benefits (in 2011$) of 
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approximately $2.8 billion for the rate-based approach and 

$3.3 billion for the mass-based approach (3 percent model 

average). For the rate-based approach, the air pollution 

health co-benefits in 2020 are estimated to be $0.7 billion 

to $1.8 billion (2011$) for a 3 percent discount rate and 

$0.64 billion to $1.7 billion (2011$) for a 7 percent 

discount rate. For the mass-based approach, the air 

pollution health co-benefits in 2020 are estimated to be 

$2.0 billion to $4.8 billion (2011$) for a 3 percent 

discount rate and $1.8 billion to $4.4 billion (2011$) for 

a 7 percent discount rate. The annual, illustrative 

compliance costs estimated by IPM and inclusive of demandside energy efficiency program and participant costs and 

MRR costs in 2020, are approximately $2.5 billion for the 

rate-based approach and $1.4 billion for the mass-based 

approach (2011$). The quantified net benefits (the 

difference between monetized benefits and compliance costs) 

in 2020 are estimated to range from $1.0 billion to $2.1 

billion (2011$) for the rate-based approach and from $3.9 

billion to 6.7 billion (2011$) for the mass-based approach, 

using a 3 percent discount rate (model average).

The EPA estimates that, in 2025, the final guidelines will 

yield monetized climate benefits (in 2011$) of approximately $10 
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billion for the rate-based approach and $12 billion for the 

mass-based approach (3 percent model average). For the ratebased approach, the air pollution health co-benefits in 2025 are 

estimated to be $7.4 billion to $18 billion (2011$) for a 3 

percent discount rate and $6.7 billion to $16 billion (2011$) 

for a 7 percent discount rate. For the mass-based approach, the 

air pollution health co-benefits in 2025 are estimated to be 

$7.1 billion to $17 billion (2011$) for a 3 percent discount 

rate and $6.5 billion to $16 billion (2011$) for a 7 percent 

discount rate. The annual, illustrative compliance costs 

estimated by IPM and inclusive of demand side energy efficiency 

program and participant costs and MRR costs in 2025, are 

approximately $1.0 billion for the rate-based approach and $3.0 

billion for the mass-based approach (2011$). The quantified net 

benefits (the difference between monetized benefits and 

compliance costs) in 2025 are estimated to range from $17

billion to $27 billion (2011$) for the rate-based approach and 

$16 billion to $26 billion (2011$) for the mass-based approach, 

using a 3 percent discount rate (model average).

The EPA estimates that, in 2030, the final guidelines will 

yield monetized climate benefits (in 2011$) of approximately $20 

billion for the rate-based approach and $20 billion for the 

mass-based approach (3 percent model average). For the rate-
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based approach, the air pollution health co-benefits in 2030 are 

estimated to be $14 billion to $34 billion (2011$) for a 3 

percent discount rate and $13 billion to $31 billion (2011$) for 

a 7 percent discount rate. For the mass-based approach, the air 

pollution health co-benefits in 2030 are estimated to be $12 

billion to $28 billion (2011$) for a 3 percent discount rate and 

$11 billion to $26 billion (2011$) for a 7 percent discount 

rate. The annual, illustrative compliance costs estimated by IPM 

and inclusive of demand side energy efficiency program and 

participant costs and MRR costs in 2030, are approximately $8.4 

billion for the rate-based approach and $5.1 billion for the 

mass-based approach (2011$). The quantified net benefits (the 

difference between monetized benefits and compliance costs) in 

2030 are estimated to range from $26 billion to $45 billion 

(2011$) for the rate-based approach and from $26 billion to $43 

billion (2011$) for the mass-based approach, using a 3 percent 

discount rate (model average).

Table [X] and Table [X] provide the estimates of the 

climate benefits, health co-benefits, compliance costs and net 

benefits of the final emission guidelines for rate-based and 

mass-based illustrative plan approaches, respectively.

Table [X]. Summary of the Monetized Benefits, Compliance Costs, 

and Net Benefits for the Final Guidelines in 2020, 2025 and 2030
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Under the Rate-Based Illustrative Plan Approach [Billions of 

2011$]a

Rate-Based Approach 

2020 2025 2030

Climate 

Benefitsb

5% discount 

rate $0.80 $3.1 $6.4 

3% discount 

rate $2.8 $10 $20 

2.5% 

discount 

rate

$4.1 $15 $29 

95th 

percentile 

at 3% 

discount 

rate

$8.2 $31 $61 

Air Quality Co-benefits Discount Rate

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

Air Quality 

Health Cobenefitsc

$0.70 

to $1.8

$0.64 

to $1.7

$7.4 

to $18

$6.7 to 

$16

$14 to 

$34

$13 to 

$31

Compliance 

Costsd $2.5 $1.0 $8.4

Net 

Benefitse

$1.0 to 

$2.1

$1.0 to 

$2.0

$17 to 

$27

$16 to 

$25

$26 to 

$45

$25 to 

$43

NonMonetized 

Benefits

Non-monetized climate benefits

Reductions in exposure to ambient NO2 and SO2

Reductions in mercury deposition
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Ecosystem benefits associated with reductions in 

emissions of NOX, SO2, PM, and mercury

Visibility impairment

a All are rounded to two significant figures, so figures may not 

sum.

b The climate benefit estimate in this summary table reflects 

global impacts from CO2 emission changes and does not account for 

changes in non-CO2 GHG emissions. Also, different discount rates 

are applied to SC-CO2 than to the other estimates because CO2

emissions are long-lived and subsequent damages occur over many 

years. The benefit estimates in this table are based on the 

average SC-CO2 estimated for a 3 percent discount rate. However, 

we emphasize the importance and value of considering the full 

range of SC-CO2 values. As shown in the RIA, climate benefits are 

also estimated using the other three SC-CO2 estimates (model 

average at 2.5 percent discount rate, 3 percent, and 5 percent; 

95th percentile at 3 percent). The SC-CO2 estimates are 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 

proposed rule. The reduction in premature fatalities each year 

accounts for over 98 percent of total monetized co-benefits from 

PM2.5 and ozone. These models assume that all fine particles, 

regardless of their chemical composition, are equally potent in 

causing premature mortality because the scientific evidence is 

not yet sufficient to allow differentiation of effect estimates 

by particle type.

d Total costs are approximated by the illustrative compliance 

costs estimated using the Integrated Planning Model for the 

final guidelines and a discount rate of approximately 5 percent. 

This estimate includes monitoring, recordkeeping, and reporting 

costs and demand-side energy efficiency program and participant 

costs.
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e The estimates of net benefits in this summary table are 

calculated using the global SC-CO2 at a 3 percent discount rate 

(model average). The RIA includes combined climate and health 

estimates based on additional discount rates.

Table [X]. Summary of the Monetized Benefits, Compliance Costs, 

and Net Benefits for the Final Guidelines in 2020, 2025 and 2030

Under the Mass-Based Illustrative 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
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Compliance 

Costsd $1.4 $3.0 $5.1

Net 

Benefitse

$3.9 to 

$6.7

$3.7 to 

$6.3

$16 to 

$26

$15 to 

$24

$26 to 

$43

$25 to 

$40

NonMonetized 

Benefits

Non-monetized climate benefits

Reductions in exposure to ambient NO2 and SO2

Reductions in mercury deposition

Ecosystem benefits associated with reductions in 

emissions of NOX, SO2, PM, and mercury

Visibility improvement

a All are rounded to two significant figures, so figures may not 

sum.

b The climate benefit estimate in this summary table reflects 

global impacts from CO2 emission changes and does not account for 

changes in non-CO2 GHG emissions. Also, different discount rates 

are applied to SC-CO2 than to the other estimates because CO2

emissions are long-lived and subsequent damages occur over many 

years. The benefit estimates in this table are based on the 

average SC-CO2 estimated for a 3 percent discount rate. However, 

we emphasize the importance and value of considering the full 

range of SC-CO2 values. As shown in the RIA, climate benefits are 

also estimated using the other three SC-CO2 estimates (model 

average at 2.5 percent discount rate, 3 percent, and 5 percent; 

95th percentile at 3 percent). The SC-CO2 estimates are 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 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 
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causing premature mortality because the scientific evidence is 

not yet sufficient to allow differentiation of effect estimates 

by particle type.

d Total costs are approximated by the illustrative compliance 

costs estimated using the Integrated Planning Model for the 

final guidelines and a discount rate of approximately 5 percent. 

This estimate includes monitoring, recordkeeping, and reporting 

costs and demand-side energy efficiency program and participant 

costs.

e The estimates of net benefits in this summary table are 

calculated using the global SC-CO2 at a 3 percent discount rate 

(model average). The RIA includes combined climate and health 

estimates based on additional discount rates.

There are additional important benefits that the EPA could 

not monetize. Due to current data and modeling limitations, our 

estimates of the benefits from reducing CO2 emissions do not 

include important impacts like ocean acidification or potential 

tipping points in natural or managed ecosystems. Unquantified 

benefits also include climate benefits from reducing emissions 

of non-CO2 greenhouse gases (e.g., nitrous oxide and methane) and 

co-benefits from reducing direct exposure to SO2, NOX and 

hazardous air pollutants (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 final action are substantial, and far exceed the costs. 

Additional details on benefits, costs, and net benefits 

estimates are provided in this RIA.
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B. Paperwork Reduction Act (PRA)

[&&&based on preliminary analysis]

The information collection requirements in this rule have 

been submitted for approval to OMB under the PRA. The 

Information Collection Request (ICR) document prepared by the 

EPA has been assigned the EPA ICR number [[&&&placeholder for 

ICR number]. You can find a copy of the ICR in the docket for 

this rule, and it is briefly summarized here. The information 

collection requirements are not enforceable until approved by 

OMB.

This rule does not directly impose specific requirements on 

state and U.S. territory governments with affected EGUs. The 

rule also does not impose specific requirements on tribal 

governments that have affected EGUs located in their area of 

Indian country. This rule does impose specific requirements on 

EGUs located in states, U.S. territories or areas of Indian 

country.

The information collection activities in this proposed rule 

are consistent with those activities defined under the Carbon 

Pollution Emission Guidelines for Existing Stationary Sources: 

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 
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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 &&&XX. You can find a 

copy of the ICR in the docket for this rule, and it is briefly 

summarized here. 

This proposed action would impose minimal new information 

collection burden on affected EGUs beyond what those affected 

EGUs would already be subject to under the authorities of CAA 

parts 75 and 98. OMB has previously approved the information 

collection requirements contained in the existing part 75 and 98 

regulations (40 CFR part 75 and 40 CFR part 98) under the 

provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et 

seq. and has assigned OMB control numbers 2060–0626 and 2060–

0629, respectively. Apart from certain reporting costs based on 

requirements in the NSPS General Provisions (40 CFR part 60, 

subpart A), which are mandatory for all owners/operators subject 

to CAA section 111 national emission standards, there are no new 

information collection costs, as the information required by 

this proposed rule is already collected and reported by other 

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 
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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.

Submit your comments on the agency’s need for this 

information, the accuracy of the provided burden estimates and 

any suggested methods for minimizing respondent burden to the 

EPA using the docket identified at the beginning of this rule. 

You may also send your ICR-related comments to OMB’s Office of 

Information and Regulatory Affairs via email to 

oria_submissions@omb.eop.gov, Attention: Desk Officer for the 

EPA. Since OMB is required to make a decision concerning the ICR 

between 30 and 60 days after receipt, OMB must receive comments 

no later than [insert date 30 days after 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]
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As required by section 609(b) of the RFA, the EPA also 

convened a Small Business Advocacy Review (SBAR) Panel to obtain 

advice and recommendations from small entity representatives

that potentially would be subject to the rule's requirements.

The SBAR Panel evaluated the assembled materials and smallentity comments on issues related to elements of an IRFA. A copy 

of the full SBAR Panel Report is available in the rulemaking 

docket.

The EPA also considered whether the separate changes that 

we are proposing to make, as explained in Section VII 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]
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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 one year. Accordingly, the EPA has 

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 
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Page 500 of 514

federalism implications, because it may impose substantial 

direct compliance costs on state or local governments, and the

federal government will not provide the funds necessary to pay 

those costs. As discussed in the Supporting Statement found in 

the docket for this rulemaking, [&&& Insert text consistent with 

PRA analysis].

The EPA consulted with state and local officials early in 

the process of developing the Clean Power Plan emission 

guidelinesEGs to permit them to have meaningful and timely input 

into its development. As described in the Federalism discussion

in the preamble to the proposed standards of performance for GHG

emissions from new EGUs (79 FR 1501, January 8, 2014), the EPA 

consulted with state and local officials in the process of 

developing the proposed standards for newly constructed EGUs. A 

detailed Federalism Summary Impact Statement (FSIS) describing 

the most pressing issues raised in pre-proposal and postproposal 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.
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F. Executive Order 13175: Consultation and Coordination with 

Indian Tribal Governments

This proposed action has tribal implications. However, it will 

neither impose substantial direct compliance costs on federally 

recognized tribal governments, nor preempt tribal law. The 

unitsEGU potentially impacted by this proposed rulemaking 

located on tribal landsIndian reservations are primarily owned 

by private entities, and in one case, partially owned by an 

agency of the United 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 unitEGU. A tribal government could also 

incur costs in the event that it seeks and is given delegated 

authority to enforce the federal plan proposed in this 

rulemaking. The EPA has, nevertheless, offered consultation to 

the tribes on whose areas of Indian country the units are 

located. As part of its general outreach to tribes regarding 

this proposed rulemaking, EPA received feedback from a number 

of tribes regarding the potential overall economic impact that 
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both the proposed Clean Power Plan and that a proposed federal 

plan rulemaking may have on them. In these instances, the EPA 

has reached out to these tribes and as part of the consultation 

on the Clean Power Plan engaged with them on their concerns 

regarding a potential federal plan. 

The EPA has conducted consultation with tribes on the Clean 

Power Plan and the Supplemental Proposal for the Clean Power 

Plan and will offer all tribes consultation on this proposed 

action. The EPA held consultations with tribes on the Clean 

Power Plan in the fall of 2014 before the agency issued its 

Supplemental Proposal for Indian Country and U.S. Territories. 

Addtionally, the EPA held consultations for tribes shortly 

following the release of itsthe supplemental proposal. The 

agency also held itsa public hearing on the supplemental 

proposal on November 19, 2014, in Phoenix, Arizonia. At this 

timethe public hearing the agency received oral comments from 

community members representing a number of tribes and a number 

of tribal officals. The agency also conducted consultation with 

tribes in the spring and summer of 2015. An overview of the 

consultations provided as part of the Clean Power Plan is 

available in section XII.F of the final Clean Power Plan 

rulemaking. 

Additionally, the EPA engaged in meaningful dialogue with 
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tribal stakeholders to obtain their feedback in the pre-propsal 

stages of this the rulemaking. We provided an update on this 

proposed rulemaking on the May 28, 2015, National Tribal Air 

Association (NTAA) and the EPA Air Policy call. Additionally, 

staff attended the National Tribal Forum conference on May 20, 

2015 and provided an overview of the Clean Power Plan and 

explained that the agency would be proposing a fededral plan. As 

required by section 7(a), the EPA’s Tribal Consultation Official 

has certified that the requirements of Executive Order 13175 

have been met in a meaningful and timely manner. A copy of the 

certification is included in the docket for this action.

Consistent with previous rulemakings impacting the power 

sector, there is significant tribal interest in these 

rulemakings because of the potential indirect impacts that rules 

such as the Clean Power Plan and this proposed federal plan may 

have on tribes. In sections II.A, III.F and VI.E of this 

rulemaking the The EPA references tribes and specifically 

solicits additional feedback from tribal officials we invite 

comments from anyon all aspects of this proposed rulemaking, 

including whether tribes whose areas of theIndian country 

contain affected tribes whether theyEGU(s) are interested in 

developing their own plan. implementing the final emission 

guidelines. Additionally, tribal stakeholders will be included 
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in the outreach that the agency will be conducting with those 

communities already overburdened communities, that isby 

pollution, which are often low-income communties, communities of 

color, , and indigenous communities. The actions that the agency 

will be takingng are outlined in VI.Esection XI of this 

preamble.

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks

The EPA interprets EO 13045 (62 FR 19885, April 23, 1997) 

as applying to those regulatory actions that concern health or 

safety risks, such that the analysis required under section 5–

501 of the Order has the potential to influence the regulation. 

This action is not subject to EO 13045 because it does not 

involve decisions on environmental health or safety risks that 

may disproportionately affect children. The EPA believes that 

the CO2 emission reductions resulting from implementation of the 

proposed guidelines, as well as substantial ozone and PM2.5 

emission reductions as a cobenefit, would further improve 

children’s health.

H. Executive Order 13211: Actions That Significantly Affect 

Energy Supply, Distribution, or Use

[PLACEHOLDER: RESPONSE TO BE BASED ON ANALYSIS FOR 111D FINAL 
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RULE]

This action, which is a significant regulatory action under 

EO 12866, is likely to have a significant effect on the supply, 

distribution, or use of energy. The EPA has prepared a Statement 

of Energy Effects for this action as follows. We estimate a 1 to 

2 percent change in retail electricity prices on average across 

the contiguous U.S. in 2025, and a 22 to 23 percent reduction in 

coal-fired electricity generation as a result of this rule. The 

EPA projects that utility power sector delivered natural gas 

prices will increase by up to 2.5 percent in 2030. For more 

information on the estimated energy effects, please refer to the 

economic impact analysis for this proposal. The analysis is 

available in the RIA, which is in the public docket.

I. National Technology Transfer and Advancement Act (NTTAA)

This proposed action does not involve technical standards. 

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations 

Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations 

Executive Order 12898 (59 FR 7629; February 16, 1994) 
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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 

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 
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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 XX 

and XX, 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 

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 
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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.153

 

153 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, 

Eds., 2014: Climate Change Impacts in the United States: The Third 

National Climate Assessment. U.S. Global Change Research Program, 

841 pp. 

IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and 

Vulnerability. Part A: Global and Sectoral Aspects. Contribution 

of Working Group II to the Fifth Assessment Report of the 

Intergovernmental Panel on Climate Change [Field, C.B., V.R. 

Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. 

Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. 
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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 

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 

 

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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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 guidelinesstandards for existing 

affected fossil fuel-fired EGUs. 

In addition to reducing CO2 emissions, the guidelines 

finalized in this rulemaking would reduce other emissions from 

affected EGUs that reduce generation due to higher adoption of 

energy efficiency and renewable energy. These emission 

reductions will include SO2 and NOx, which form ambient PM2.5 and 

ozone in the atmosphere, and hazardous air pollutants (HAP), 

such as mercury and hydrochloric acid. In the final rule 

revising the annual PM2.5 NAAQS,154 the EPA identified low-income 

populations as being a vulnerable population for experiencing 

 

154 “National Ambient Air Quality Standards for Particulate Matter, 

Final Rule,” 78 FR 3086 (Jan. 15, 2013).
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adverse health effects related to PM exposures. Low-income 

populations have been generally found to have a higher 

prevalence of pre-existing diseases, limited access to medical 

treatment, and increased nutritional deficiencies, which can 

increase this population’s risksusceptibility to PM-related and 

ozone-related effects.155 Therefore, In areas where this 

rulemaking reduces exposure to PM2.5, ozone, and methylmercury, 

low-income populations will also benefit from such emissions 

reductions. The RIA for this rulemaking, included in the docket 

for this rulemaking, provides additional information regarding 

the health and ecosystem effects associated with these emission 

reductions. 

Additionally, as outlined in the community and environmental 

justice considerations section IX of this preamble, the agency 

believesEPA has taken a number of actions to help ensure that all 

communities, including overburdened communities will benefit from 

this rulemaking because of the direct health benefits associated 

with the CO2 and conventional pollutant reductions. Furthermore, 

this action will complement EPA actions already in place to address 

 

155 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 

www.cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546.
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conventional pollutant emissions and will result in further 

positive health benefits for overburden communities. To help in 

the identification of those communities overburdened by this 

rulemaking as noted in section IX.A of this preamble, the EPA has 

conducted a proximity analysis for this rulemaking, which is 

located in the docket.not have potential disproportionately high 

and adverse human health or environmental effects on vulnerable 

communities. The EPA consulted its May 2015, Guidance on 

Considering Environmental Justice During the Development of 

Regulatory Actions, when crafting this rulemaking.determining what

actions to take.156 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. 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.

 

156 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.
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