Vol. 80 Friday, 

No. 205 October 23, 2015 

Part IV 

Environmental Protection Agency 

40 CFR Parts 60, 62, and 78 

Federal Plan Requirements for Greenhouse Gas Emissions From Electric 

Utility Generating Units Constructed on or Before January 8, 2014; Model 

Trading Rules; Amendments to Framework Regulations; Proposed Rule 

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64966 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 60, 62, and 78 

[EPA–HQ–OAR–2015–0199; FRL 9930–67– 

OAR] 

RIN 2060–AS47 

Federal Plan Requirements for 

Greenhouse Gas Emissions From 

Electric Utility Generating Units 

Constructed on or Before January 8, 

2014; Model Trading Rules; 

Amendments to Framework 

Regulations 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: In this action, the 

Environmental Protection Agency (EPA) 

is proposing a federal plan to implement 

the greenhouse gas (GHG) emission 

guidelines (EGs) for existing fossil fuelfired electric generating units (EGUs) 

under the Clean Air Act (CAA). The EGs 

were proposed in June 2014 and 

finalized on August 3, 2015 as the 

Carbon Pollution Emission Guidelines 

for Existing Stationary Sources: Electric 

Utility Generating Units (also known as 

the Clean Power Plan or EGs). This 

proposal presents two approaches to a 

federal plan for states and other 

jurisdictions that do not submit an 

approvable plan to the EPA: a rate-based 

emission trading program and a massbased emission trading program. These 

proposals also constitute proposed 

model trading rules that states can adopt 

or tailor for implementation of the final 

EGs. The federal plan is an important 

measure to ensure that congressionally 

mandated emission standards under the 

authority of the CAA are implemented. 

The proposed federal plan is related to 

but separate from the final EGs. The 

final EGs establish the best system of 

emission reduction (BSER) for 

applicable fossil fuel-fired EGUs in the 

form of a carbon dioxide (CO2) emission 

performance rate for steam-fired EGUs 

and a CO2 emission performance rate for 

natural gas-fired combined cycle 

(NGCC) units, and provide guidance and 

criteria for the development of 

approvable state plans. The purpose of 

the proposed federal plan is to establish 

requirements directly applicable to a 

state’s affected EGUs that meet these 

emission performance levels, or the 

equivalent statewide goal, in order to 

achieve reductions in CO2 emissions in 

the case where a state or other 

jurisdiction does not submit an 

approvable plan. The stringency of the 

emission performance levels established 

in the final EGs will be the same 

whether implemented through a state 

plan or a federal plan. The EPA is also 

proposing enhancements to the CAA 

section 111(d) framework regulations 

related to the process and timing for 

state plan submissions and EPA actions. 

The EPA intends to finalize both the 

rate-based and mass-based model 

trading rules in summer 2016. 

DATES: Comments. Comments must be 

received on or before January 21, 2016. 

Public Hearing. The EPA will hold 

public hearings on the proposal. Details 

will be announced in a separate Federal 

Register document. 

ADDRESSES: Submit your comments, 

identified by Docket ID No. EPA–HQ– 

OAR–2015–0199, to the Federal 

eRulemaking Portal: http://

www.regulations.gov. Follow the online 

instructions for submitting comments. 

Once submitted, comments cannot be 

edited or withdrawn. The EPA may 

publish any comment received to its 

public docket. Do not submit 

electronically any information you 

consider to be Confidential Business 

Information (CBI) or other information 

whose disclosure is restricted by statute. 

Multimedia submissions (audio, video, 

etc.) must be accompanied by a written 

comment. The written comment is 

considered the official comment and 

should include discussion of all points 

you wish to make. The EPA will 

generally not consider comments or 

comment contents located outside of the 

primary submission (i.e., on the web, 

cloud, or other file sharing system). For 

additional submission methods, the full 

EPA public comment policy, 

information about CBI or multimedia 

submissions, and general guidance on 

making effective comments, please visit 

http://www2.epa.gov/dockets/

commenting-epa-dockets. 

Instructions: Direct your comments on 

the federal plan requirements proposed 

rule to Docket ID No. EPA–HQ–OAR– 

2015–0199. The EPA’s policy is that all 

comments received will be included in 

the public docket and may be made 

available online at http://

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be confidential business 

information (CBI) or other information 

whose disclosure is restricted by statute. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through http://

www.regulations.gov or email. The 

http://www.regulations.gov Web site is 

an ‘‘anonymous access’’ system, which 

means the EPA will not know your 

identity or contact information unless 

you provide it in the body of your 

comment. If you send an email 

comment directly to the EPA without 

going through http://

www.regulations.gov, your email 

address will be automatically captured 

and included as part of the comment 

that is placed in the public docket and 

made available on the Internet. If you 

submit an electronic comment, the EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 

disk or CD–ROM you submit. If the EPA 

cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, the EPA may not 

be able to consider your comment. 

Electronic files should avoid the use of 

special characters, any form of 

encryption and be free of any defects or 

viruses. 

Docket: The EPA has established a 

docket for this action under Docket ID 

No. EPA–HQ–OAR–2015–0199. The 

EPA has previously established a docket 

for the January 8, 2014, Clean Power 

Plan proposal under Docket ID No. 

EPA–HQ–OAR–2009–0559. All 

documents in the docket are listed in 

the http://www.regulations.gov index. 

Although listed in the index, some 

information is not publicly available, 

e.g., CBI or other information whose 

disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, will be publicly 

available only in hard copy form. 

Publicly available docket materials are 

available either electronically at http:// 

www.regulations.gov or in hard copy at 

the EPA Docket Center EPA/DC, EPA 

WJC West Building, Room 3334, 1301 

Constitution Ave. NW., Washington, 

DC. The Public Reading Room is open 

from 8:30 a.m. to 4:30 p.m., Monday 

through Friday, excluding holidays. The 

telephone number for the Public 

Reading Room is (202) 566–1744, and 

the telephone number for the EPA 

Docket Center is (202) 566–1742. 

FOR FURTHER INFORMATION CONTACT: Ms. 

Toni Jones, Fuels and Incineration 

Group, Sector Policies and Programs 

Division (E143–05), Environmental 

Protection Agency, Research Triangle 

Park, North Carolina 27711; telephone 

number: (919) 541–0316; fax number: 

(919) 541–3470; email address: 

jones.toni@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Acronyms and Abbreviations. The 

following acronyms and abbreviations 

are used in this document. 

ANSI American National Standards 

Institute 

ARP Acid Rain Program 

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ATCS Allowance Tracking and Compliance 

System 

BSER Best system of emission reduction 

CAA Clean Air Act 

CAIR Clean Air Interstate Rule 

CARB California Air Resources Board 

CBI Confidential Business Information 

CEIP Clean Energy Incentive Program 

CEMS Continuous emissions monitoring 

system 

CFCs Chlorofluorocarbons 

CISWI Commercial Industrial Solid Waste 

Incinerators 

CFR Code of Federal Regulations 

CHP Combined heat and power 

CO2 Carbon dioxide 

CO2e Carbon dioxide equivalent 

CSAPR Cross-state Air Pollution Rule 

DOE U.S. Department of Energy 

DOI U.S. Department of the Interior 

DOL U.S. Department of Labor 

DS–EE Demand-Side Energy Efficiency 

EE Energy efficiency 

EGs Emission Guidelines 

EGU Electric generating unit 

EIA Energy Information Administration 

EJ Environmental justice 

EM&V Evaluation, measurement, and 

verification 

EPA Environmental Protection Agency 

EO Executive Order 

ERC Emission rate credit 

FERC Federal Energy Regulatory 

Commission 

FIP Federal implementation plan 

FR Federal Register 

GHG Greenhouse gas 

GHGRP Greenhouse Gas Reporting Program 

GJ/h Gigajoule per hour 

HAP Hazardous air pollutants 

ICR Information collection request 

IGCC Integrated gasification combined 

cycle facility 

IPM Integrated Planning Model 

IPCC Intergovernmental Panel on Climate 

Change 

ISO/RTO Independent System Operator/

Regional Transmission Organization 

lbs Pounds 

LML Lowest measured PM2.5 levels 

MATS Mercury and Air Toxics Standards 

M&V Measurement and verification 

MMBtu/h Million British Thermal units per 

hour 

MSW Municipal solid waste 

MW Megawatts 

MWh Megawatt-hours 

NAAQS National Ambient Air Quality 

Standards 

NAICS North American Industrial 

Classification System 

NERC North American Electric Reliability 

Corporation 

NGCC Natural gas combined cycle 

NSPS New source performance standards 

NSR New Source Review 

NTTAA National Technology Transfer and 

Advancement Act 

NODA Notice of data availability 

NOX Nitrogen oxides 

OAP Office of Atmospheric Programs 

OAQPS Office of Air Quality Planning and 

Standards 

PRA Paperwork Reduction Act 

PSD Prevention of significant deterioration 

PUC Public Utility Commission 

RCT Randomized control trials 

RE Renewable energy 

REC Renewable Energy Certificate 

RFA Regulatory Flexibility Act 

RGGI Regional Greenhouse Gas Initiative 

RIA Regulatory impact analysis 

RPS Renewable Portfolio Standard 

SCT Stationary combustion turbine 

SGU Steam generating unit 

SIP State implementation plan 

SO2 Sulfur dioxide 

TRM Technical Reference Manual 

TSD Technical support document 

The Court U.S. Court of Appeals for the 

District of Columbia Circuit 

TTN Technology Transfer Network 

UMRA Unfunded Mandates Reform Act 

UNFCCC United Nations Framework 

Convention on Climate Change 

U.S. United States 

WWW World Wide Web 

Organization of This Document. The 

following outline is provided to aid in 

locating information in this preamble. 

I. General Information 

A. Executive Summary 

B. Organization and Approach for This 

Proposed Rule 

1. The Rate-Based Approach 

2. The Mass-Based Approach 

3. Other Proposed Actions 

C. Who does the proposed action apply to? 

1. What is an affected electric utility 

generating unit? 

2. How To Determine if a Unit Is Covered 

by an Approved and Effective State Plan 

D. What should I consider as I prepare my 

comments? 

II. Background Information 

A. What is the regulatory development 

background for this proposed rule? 

B. What is the purpose of this Proposed 

Rule? 

1. Federal Plan 

2. Model Trading Rule 

C. Legal Authority 

D. Timing of EPA Actions on the Model 

Trading Rules, Federal Plan, and Other 

Proposed Actions 

E. Use of the Model Trading Rule as a 

Backstop 

III. Federal Plan Structure To Achieve 

Reductions 

A. Overview 

1. Interactions With State Plans and Scope 

of Trading 

2. Addressing Potential Leakage and 

Interstate Effects 

3. Provisions To Encourage Early Action 

B. Inventory of Emissions 

C. Affected EGUs 

D. Compliance Schedule 

E. Addressing Reliability Concerns 

F. Worker Certification 

G. Remaining Useful Lives and Potential 

for ‘‘Stranded Assets’’ 

H. Implications for Other EPA Programs 

and Rules 

1. Title V Permitting 

2. Implications for New Source Review 

Program 

3. Interactions With Other EPA Rules 

I. Administrative Appeals Process 

J. Consistency of Program Structure With 

Clean Air Act Authority 

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

2. Use of Market Techniques To Implement 

Standards of Performance Under the 

Clean Air Act 

IV. Rate-Based Implementation Approach 

A. Overview 

B. Rate Goals 

C. Crediting Mechanism 

1. ERCs Generated and Owed Against a 

Standard 

2. Incremental NGCC ERCs 

3. Eligible Emission Reduction Measures 

for ERC Generation 

D. ERC Tracking and Compliance 

Operations 

1. Designated Representatives and 

Alternate Designated Representatives 

2. ERC Tracking and Compliance System 

3. Tracking System Requirements 

4. Compliance and General Accounts 

5. Compliance Demonstration 

6. Recordation of ERC Generation and ERC 

Issuance 

7. Independent Verifiers 

8. Evaluation, Measurement, and 

Verification (EM&V) Plans, Monitoring 

and Verification (M&V) Reports, and 

Verification Reports 

9. ERC Transfers and Trading 

10. Compliance With Emissions Standards 

11. Other ERC Tracking and Compliance 

Operations Provisions 

12. Banking of ERCs 

13. Emissions Monitoring and Reporting 

E. Federal Plan and State Plan Interactions 

1. Interstate Trading 

2. Treatment of States Entering or Exiting 

the Trading Program 

V. Mass-Based Implementation Approach 

A. Trading Program Overview 

B. Statewide Mass-Based Emissions Goals 

C. Compliance Timing and Allowance 

Banking 

D. Initial Distribution of Allowances 

1. Proposed Allocation Approach and 

Alternatives 

2. Timing of Allowance Recordation 

3. Allowance Set-Asides To Address 

Leakage to New Sources 

4. Provisions To Encourage Early Action 

5. Allocations to Units That Change Status 

E. State-Determined Allowance 

Distribution 

F. Treatment of States Entering or Exiting 

the Trading Program 

G. Allowance Tracking, Compliance 

Operations, and Penalties 

1. Designated Representatives and 

Alternate Designated Representatives 

2. Allowance Tracking and Compliance 

System 

3. Compliance and General Accounts 

4. Recordation of Allowance Allocations 

and Transfers 

5. Compliance With Emissions Limitations 

6. Other Allowance Tracking and 

Compliance Operations Provisions 

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 

1. Federal Plan Becomes Effective Prior To 

Approval of a State or Tribal Plan 

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64968 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Proposed Rules 

1For simplicity, at times this document may refer 

to the co-proposed federal plans as ‘‘the federal 

plan.’’ (It may refer to the model trading rules in 

the singular as well.) Even though the singular is 

used, this term is meant to encompass both the 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 statespecific federal plans. In other words, the EPA 

intends to finalize ‘‘the federal plan’’ as a series of 

state-specific ‘‘federal plans.’’ This is consistent 

with the agency’s prior practice in other 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. 

2. State or Tribe Takes Delegation of the 

Federal Plan 

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. Error Corrections 

E. Completeness Criteria 

F. Update to Deadlines for EPA Actions 

G. Proposed Interpretation Regarding 

Existing Sources That Modify or 

Reconstruct 

H. 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) and 1 CFR 

Part 51 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

I. General Information 

A. Executive Summary 

In the CAA, Congress created a 

partnership between the EPA and the 

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

the EPA establishes emission 

performance levels based on its 

determination of the BSER for existing 

sources of air pollution and provides 

guidelines for state plans to apply 

standards of performance to their 

sources that meet the BSER level of 

performance. The EPA promulgated EGs 

under CAA section 111(d) which set 

source-level CO2 emission performance 

rates for the EGUs at certain large fossil 

fuel-fired power plants (‘‘affected 

EGUs’’). States then apply these EGs to 

their sources in developing state plans 

to achieve these emission performance 

levels for EPA approval, or initial 

submittals, by September 6, 2016. The 

amount of reductions in CO2 that the 

EPA determined to be achievable for 

these sources is based on its 

determination of what constitutes the 

BSER. This determination is finalized in 

the EGs, which are designed to 

maximize the flexibility of both states 

and affected EGUs in meeting CO2

emissions performance rates. While 

states may impose the emission rates 

directly on their affected EGUs, states 

also have the option of submitting more 

tailored plans that meet state-specific 

emissions goals. The EGs also provide 

flexibility by allowing for emissions 

trading and multi-state compliance 

options. 

While it has been the EPA’s 

longstanding view that the statute 

identifies states as the preferred 

implementers of CAA programs, the 

agency makes clear in the EGs that 

states cannot and will not be penalized 

for failing to participate in this program. 

However, if a state does not submit an 

approvable plan under section 111(d) of 

the CAA, the EPA will develop, 

implement, and enforce a federal plan to 

reduce CO2 from the fossil fuel-fired 

power plants in that state. This is 

wholly consistent with the ‘‘cooperative 

federalism’’ structure of the CAA and 

many of our nation’s other 

environmental laws. In addition, we 

have heard from states and other 

stakeholders that it would be helpful for 

the agency to present model designs for 

state plans, and a federal plan would be 

an appropriate means of doing that. 

Accordingly, the EPA proposes a 

federal plan under section 111(d) of the 

CAA for the control of CO2, a GHG 

pollutant, from certain emitting fossil 

fuel-fired power plants, in the event that 

some states do not adopt their own 

plans. Specifically, the EPA is 

proposing approaches in the form of 

mass- and rate-based trading options 

that provide flexibility in implementing 

emission standards for a state’s affected 

EGUs. Both proposed approaches to the 

federal plan would require affected 

EGUs to meet emission standards set 

using the CO2 emission performance 

rates in the EGs. The federal plan will 

achieve the same levels of emissions 

performance as required of state plans 

under the EGs. The EPA will 

promulgate a final federal plan for only 

the affected EGUs in states that the EPA 

determines did not submit an 

approvable plan. 

At the same time, these two proposed 

options offer states model trading rules 

that the states can follow in developing 

their own plans in order to capitalize on 

the flexibility built into the final EGs. 

Thus, this document proposes four 

discrete actions: (1) A rate-based federal 

plan for each state with affected EGUs; 

(2) a mass-based federal plan for each 

state with affected EGUs; (3) a ratebased model trading rule for potential 

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

model trading rule for potential use by 

any state. The regulatory text of each 

federal plan and corresponding model 

trading rule is identical, except as 

indicated otherwise within the text of 

the model rule (for instance, the EPA is 

providing model rule text for states to 

use related to the crediting of a broader 

set of clean energy resources than is 

being proposed in the federal plan). 

The EPA intends to finalize both the 

rate-based and mass-based model 

trading rules in summer 2016. The EPA 

will finalize a federal plan for only a 

given state in the event that the state 

does not submit an approvable plan by 

the deadlines specified in the final EGs 

and the EPA takes action finding that 

the state has failed to submit a plan, or 

disapproving a submitted plan because 

it does not meet the requirements of the 

EGs.1 Indeed, states may simply choose 

to accept a federal plan for their sources 

rather than undertake the development 

of a plan of their own by not submitting 

a state plan. Under this proposed rule, 

a federal plan promulgated for a 

particular state would take the form of 

either the mass-based model trading 

rule or the rate-based model trading 

rule. The EPA currently intends to 

finalize a single approach (i.e., either the 

mass-based or rate-based approach) for 

every state in which it promulgates a 

federal plan, given the benefits of a 

broad trading program, as discussed in 

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2For example, in the context of a mass- or ratebased trading program, a state may submit a plan 

with alternative components other than those 

described, so long as the program includes each of 

the requirements and the state satisfactorily 

demonstrates in the state plan submittal that such 

alternative means of addressing the requirements 

are as stringent as the presumptively approvable 

approach as described, and therefore provide for the 

implementation of the state plan’s emission 

standards. 

section I.B of this preamble. We invite 

comment on which approach, i.e., either 

mass-based or rate-based trading, should 

be selected if we opt to finalize a single 

approach. 

It is the EPA’s intention to give the 

states as much opportunity as possible 

to set their own course for carrying out 

the EGs. Even where a federal plan is 

put in place for a particular state, that 

state will still be able to submit a plan, 

which, upon approval, will allow the 

state and its sources to exit the federal 

plan. In addition, as discussed in 

section VI.A of this preamble, states 

may take delegation of administrative 

aspects of the federal plan in order to 

become the primary implementers. And 

as discussed in sections V.E and VII.A 

of this preamble, states may submit 

partial state plans in order to take over 

the implementation of a portion of a 

federal plan. For instance, in a massbased 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, there are stand-alone 

portions of the model trading rules, 

such as the evaluation, measurement, 

and verification (EM&V) procedures, 

that would be approvable even if a state 

adopted an approach that differs from 

the federal plan. The model trading 

rules serve as a mechanism to facilitate 

larger trading markets since consistency 

with the federal plan allows trading 

across both the state and federal 

programs. The EPA expects a larger 

trading region is likely to result in lower 

overall costs. These and other aspects of 

the model trading rules and federal plan 

provide additional support for this rule 

as proposed. Thus, the proposed rule 

would ensure that congressionally 

mandated emission standards under 

authority of section 111 of the CAA are 

implemented, either by the states in the 

first instance, or by the EPA where 

needed. 

The agency is proposing a finding that 

it is necessary or appropriate to 

implement a CAA section 111(d) federal 

plan for the affected EGUs located in 

Indian country. CO2 emission 

performance rates for these facilities 

were finalized in the EGs. Tribes 

generally may seek ‘‘treatment as a 

state’’ (TAS) and submit a tribal plan to 

implement CAA programs, including 

programs under CAA section 111(d), 

and this proposed finding does not 

preclude tribes from doing that. 

However, tribes are not subject to the 

deadlines applicable to state action 

under the EGs and in the absence of a 

federal plan, CO2 emissions from these 

EGUs could go unregulated. Therefore, 

as discussed in section VI.D of this 

preamble, we are proposing a necessary 

or appropriate finding. 

This document also proposes certain 

enhancements to the process and timing 

for state submittals and EPA action in 

the CAA section 111(d) framework 

regulations of 40 CFR part 60, subpart 

B (these proposals are not a part of the 

federal plan or model trading rules). 

These changes, if finalized, would be 

applicable under the Clean Power Plan 

and other CAA section 111(d) rules. 

These changes clarify the availability of 

certain procedural mechanisms similar 

to those available under CAA section 

110 (such as calls for plan revisions and 

the availability of ‘‘conditional 

approvals,’’ etc.). They also extend the 

deadlines for EPA action, in part to 

conform with the timelines in the EGs. 

These changes do not alter the timelines 

for state action under the EGs and do 

not alter the submission requirements 

established in the EGs. Finally, the 

agency proposes to clarify and request 

comment on an interpretive issue raised 

in the Clean Power Plan proposal 

regarding whether a reconstruction or 

modification that is subject to a CAA 

section 111(b) standard moves an 

existing source out of a CAA section 

111(d) program. These proposed 

changes are discussed in section VII of 

this preamble. The agency intends to 

finalize these changes earlier than the 

finalization of the model trading rules. 

In proposing a federal plan, the EPA 

considered a variety of potential 

impacts that its action might have on 

the environment, on businesses, 

particularly in the energy sector, and on 

the reliability of the electrical grid. The 

agency gave extensive consideration to 

impacts on vulnerable communities, 

particularly low-income communities, 

communities of color, and indigenous 

communities. These considerations are 

discussed in sections III, VIII, IX, and X 

of this preamble. 

The agency convened a Small 

Business Advocacy Review Panel under 

the Regulatory Flexibility Act and has 

completed an Initial Regulatory 

Flexibility Analysis (IRFA). Various 

recommendations from the Panel are 

found reflected throughout this 

proposal. In section X of this preamble, 

the agency explains how it has 

conducted or intends to conduct all 

other statutory or executive order (EO) 

reviews that apply to this proposed 

action. The EPA also explains in this 

document how it proposes to take into 

consideration the ‘‘remaining useful 

lives’’ of affected EGUs in the design of 

the proposed federal plan, as discussed 

below in section III.G of this preamble. 

The agency considered the impacts 

this action could have on the electricity 

grid and developed options for 

compliance that are cost-effective and 

that provide substantial flexibility for 

the affected EGUs that will 

accommodate the parties charged with 

maintaining the reliability of electrical 

power. A key feature of the proposed 

federal plan and model trading rule is 

that the flexibility inherent in both of 

the two approaches (i.e., rate-based or 

mass-based trading) enables the EPA 

and the states to create a level of 

flexibility for affected EGUs that allows 

owners and operators to determine the 

best way to achieve emission 

reductions, at the EGU-, state-, multistate-, regional-, or national level. As a 

result, compliance strategies can mirror, 

or be integrated with, the ongoing 

operations of the current electricity grid 

as it continues to serve its primary 

critical function of ensuring an 

uninterrupted supply of affordable and 

reliable electricity. This flexibility is 

especially valuable whenever the need 

to address specific reliability concerns 

arises. It allows owners and operators of 

reliability-critical EGUs to continue to 

meet their compliance obligations while 

operating to maintain electric reliability. 

The EPA outlined and initiated the 

Clean Energy Incentive Program (CEIP) 

in the final EGs (see section VIII of the 

final EGs). The program is designed to 

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3The agency recognizes that the ‘‘remaining 

useful lives’’ of facilities subject to a CAA section 

111(d) federal plan is a factor that it must consider 

at the time it implements the federal plan. This 

factor, and how the agency proposes to consider it, 

is discussed in section III.G of this preamble below. 

incentivize investment in certain types 

of renewable energy (RE) projects, as 

well as demand-side energy efficiency 

(EE) projects implemented in lowincome communities, that generate 

MWh or reduce end-use energy demand 

during 2020 and/or 2021. The EPA 

proposes to apply the CEIP in all states 

subject to either a rate-based or massbased federal plan. 

We also reviewed impacts that this 

action could have on the environment 

and the need to ensure environmental 

integrity of the program as well as avoid 

unintended environmental impacts. We 

took measures to ensure that the 

reductions in carbon emissions this plan 

will achieve are real, and not just 

apparent. As in the EGs, in both the 

rate- and mass-based approaches, the 

EPA has incorporated components to 

address the concern that the dynamics 

of either a rate- or mass-based trading 

program could incentivize shifting 

generation from existing units in ways 

that would result in more CO2 emissions 

than would otherwise be expected, or 

that undermine the purpose of the CAA 

section 111(d) program. 

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 

co-pollutants, 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 EGs, the EPA emphasized 

the importance of state actions to ensure 

that in developing their respective 

compliance plans the states addressed 

the concerns and priorities of vulnerable 

communities. In the process of 

developing a final federal plan, the EPA 

will take actions to address those 

concerns as well. In addition to the 

public hearings that the EPA will be 

holding for all members of the American 

public on this proposed rulemaking, we 

will also be conducting a national 

webinar and outreach meeting(s) in all 

ten regions on this proposed rulemaking 

for communities. The goal of these 

outreach activities is to provide 

communities with the information they 

need to understand how the proposed 

rulemaking will potentially impact their 

respective communities. At the same 

time, this information will be useful in 

helping communities engage the EPA 

during our comment period, as well as 

with their states during the state plan 

development process. We will also be 

providing other outreach and support 

activities for vulnerable communities, 

which are outlined in the community 

and environmental justice (EJ) 

considerations in section IX.B of this 

preamble. 

B. Organization and Approach for This 

Proposed Rule 

In this action, the EPA is proposing a 

federal plan to implement the Clean 

Power Plan EGs for affected fossil fuelfired EGUs operating in states that do 

not have approved state plans. 

Specifically, the EPA is co-proposing 

two different approaches to a federal 

plan to implement the Clean Power Plan 

EGs—a rate-based trading approach and 

a mass-based trading approach. While 

establishing emission standards for 

affected EGUs that would be directly 

enforceable against the owners and 

operators of the source, both approaches 

would grant EGUs substantial flexibility 

in meeting their compliance obligations. 

For this reason, among others, these 

proposed approaches also serve as two 

proposed model trading rules that states 

may adopt or tailor in designing their 

own plans. 

The EGs provide that states have until 

September 6, 2016 (or upon making an 

initial submittal, until September 6, 

2018) to submit state plans, and the EPA 

does not intend to finalize and 

implement the federal plan for any 

states prior to the agency’s action of 

determining a failure to submit a state 

plan or disapproving a state plan. At the 

same time, in order to support states’ 

consideration of adoption of one of the 

model trading rules as an approvable 

state plan, the agency intends to finalize 

either or both model rule options 

presented in this proposed rule by 

summer 2016, prior to the deadline for 

state submittals. 

The EPA currently intends to finalize 

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

promulgated federal plans for particular 

states in order to enhance the 

consistency of the federal trading 

program, achieve economies of scale 

through a single, broad trading program, 

ensure efficient administration of the 

program, and simplify compliance 

planning for affected EGUs. The EPA 

recognizes that the mass-based trading 

approach would be more 

straightforward to implement compared 

to the rate-based trading approach, both 

for industry and for the implementing 

agency. The EPA, industry, and many 

state agencies have extensive knowledge 

of and experience with mass-based 

trading programs. The EPA has more 

than two decades of experience 

implementing federally-administered 

mass-based emissions budget trading 

programs including the Acid Rain 

Program (ARP) sulfur dioxide (SO2) 

trading program, the Nitrogen Oxides 

(NOX) Budget Trading Program, CAIR, 

and CSAPR. The tracking system 

infrastructure exists and is proven 

effective for implementing such 

programs. The EPA requests comment 

on which approach—mass-based or ratebased trading—is preferred for the 

federal plan. Some stakeholders have 

suggested there could be utility in the 

availability of both approaches based on 

the unique circumstances of particular 

states. The EPA recognizes that it 

remains potentially possible to finalize 

a different approach to a federal plan in 

some circumstances, but believes that in 

general, and consistent with prior 

federal trading programs such as 

CSAPR, creating a single, broad program 

has the most advantages. 

The stringency of the proposed 

federal plan is the same as the CO2

emission performance rates established 

for affected EGUs in the EGs. As 

explained in the final EGs, the EPA 

determined the CO2 emission 

performance rates through the 

application of the BSER. In the EGs, the 

EPA has taken final action on the BSER 

for CO2 emissions from existing fossil 

fuel-fired EGUs. Any comments on this 

proposed rule relating to the BSER, its 

stringency, rationale, or legal basis, will 

not be considered as, by definition, they 

will be beyond the scope of this action.3

1. The Rate-Based Approach 

In the first approach, the EPA would 

implement a rate-based emissions 

trading program. In a rate-based 

program, affected EGUs must meet an 

emission standard, derived from the 

EGs, expressed as a rate of pounds of 

CO2 per megawatt hour (lbs/MWh). If 

sources emit above their assigned rate, 

they must acquire a sufficient number of 

emission rate credits (ERC), each 

representing a zero-emitting megawatt 

hour (MWh), to bring their rate of 

emissions into compliance. Emission 

rate credits (ERCs) may be generated by 

affected EGUs or by other entities that 

supply zero- or low-emitting electricity 

resources to the grid through an 

approval and recognition process that 

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4An affected EGU is any fossil fuel-fired EGU that 

was in operation or had commenced construction 

as of January 8, 2014, and is therefore an ‘‘existing 

source’’ for purposes of CAA section 111, but in all 

other respects would meet the applicability criteria 

for coverage under the GHG standards for new fossil 

fuel-fired EGUs. 

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). 

the EPA will administer. ERCs may be 

bought and sold, or banked for use in 

later years. The rate-based approach is 

explained in greater detail in section IV 

of this preamble. 

2. The Mass-Based Approach 

The second approach to a federal plan 

that the EPA is proposing in this action 

is a mass-based trading program. In a 

mass-based program, the EPA would 

create a state emissions budget equal to 

the total tons of CO2 allowed to be 

emitted by the affected EGUs in each 

state, consistent with the mass goals 

established in the EGs. The EPA would 

initially distribute the allowances 

within each state budget—less three 

proposed allowance set-asides—to the 

affected EGUs based on their historical 

generation. Allowances may then be 

transferred, bought, and sold on the 

open market, or banked for future use. 

The compliance obligation on each of 

the affected EGUs is to surrender the 

number of allowances sufficient to cover 

the EGU’s respective emissions at the 

end of a given compliance period. The 

EPA is also proposing as a part of the 

mass-based approach three set-asides of 

allowances: (1) For a Clean Energy 

Incentive Program; (2) to support 

renewable energy (RE) projects; and (3) 

to allocate allowances based on an 

updating measurement of affected-EGU 

generation. The EPA is also proposing 

that a jurisdiction may choose to replace 

the federal plan allocation provisions 

with its own allowance allocation 

provisions. The mass-based approach is 

explained in greater detail in section V 

of this preamble. 

3. Other Proposed Actions 

The EPA is proposing in this action a 

finding that it is necessary or 

appropriate to regulate affected EGUs in 

certain parts of Indian country via a 

federal plan. This is discussed in 

section VI.D of this preamble. 

In this action, the EPA is also 

proposing a number of changes to the 

framework CAA section 111(d) 

regulations of 40 CFR part 60, subpart 

B. These changes generally are intended 

to provide enhancements to the process 

for state plan submissions and the 

timing of EPA actions related to state 

plans and the federal plan. Specifically, 

the EPA proposes six changes, to 

include: (1) Partial approval/

disapproval mechanisms similar to CAA 

section 110(k)(3); (2) a conditional 

approval mechanism similar to CAA 

section 110(k)(4); (3) a mechanism for 

the EPA to make calls for plan revisions 

similar to the ‘‘SIP-call’’ provisions of 

CAA section 110(k)(5); (4) an error 

correction mechanism similar to CAA 

section 110(k)(6); (5) completeness 

criteria and a process for determining 

completeness of state plans and 

submittals similar to CAA section 

110(k)(1) and (2); and (6) updates to the 

deadlines for EPA action. These 

proposed changes are explained in 

greater detail in section VII of this 

preamble. They are not a component of 

the proposed federal plan, or changes in 

the EGs. If these changes are finalized, 

they will be applicable to other CAA 

section 111(d) rules. The EPA intends to 

finalize these changes earlier than the 

finalization of the model trading rules. 

C. Who does the Proposed Action apply 

to? 

Regulated Entities. Existing fossil 

fuel-fired EGUs (or affected EGUs) 

covered by the final Clean Power Plan 

that are located in a state that does not 

have an EPA-approved state plan are 

potentially subject to this proposed 

action. Affected EGUs are those that 

were in operation, or had commenced 

construction, on or before January 8, 

2014.4 The following North American 

Industrial Classification System 

(NAICS) codes apply as shown in Table 

1 of this preamble: 

TABLE 1—EXAMPLES OF POTENTIALLY REGULATED ENTITIES a

Category NAICS code Examples of potentially regulated entities 

Industry ..................................................... 221112 Fossil fuel electric power generating units. 

State/Local Government ........................... b 221112 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). bState or local government-owned and operated establishments are classified according to the activity in which they are engaged.

This table is not intended to be 

exhaustive, but rather provides a general 

guide for identifying entities likely to be 

affected by the proposed action. 

Whether an affected EGU is affected by 

this action is described in the 

applicability criteria in 40 CFR 60.5845 

and 60.5850 of subpart UUUU. 

Questions regarding the applicability of 

this action to a particular entity should 

be directed to the person listed in the 

preceding FOR FURTHER INFORMATION

CONTACT section of this preamble. 

1. What is an affected electric utility 

generating unit? 

For the federal plan, the definition of 

an affected EGU is identical to the 

definition in the final Clean Power Plan. 

Additionally, the applicability of the 

federal plan is consistent with the EGs, 

where an affected EGU subject to the 

federal plan is any steam generating unit 

(SGU), integrated gasification combined 

cycle (IGCC), or stationary combustion 

turbine (SCT) that was in operation or 

had commenced construction as of 

January 8, 2014,5 and that meets certain 

criteria, which differ depending on the 

type of unit. The criteria to be an 

affected EGU are as follows: A unit, if 

it is a SGU or IGCC, must serve a 

generator capable of selling greater than 

25 MW (Megawatts) to a utility power 

distribution system, have a base load 

rating greater than 260 GJ/h (250 

MMBtu/h) heat input of fossil fuel 

(either alone or in combination with any 

other fuel), and historically have 

supplied more than 1⁄3 of its potential 

electric output and 219,000 MWh as 

net-electric sales on any 3 calendar year 

basis. If a unit is a SCC, the unit must 

meet the definition of a combined cycle 

or combined heat and power (CHP) 

combustion turbine, serve a generator 

capable of selling greater than 25 MW to 

a utility power distribution system, have 

a base load rating of greater than 260 GJ/ 

h (250 MMBtu/h), and historically have 

combusted more than 90 percent natural 

gas on a heat input basis on an annual 

basis. 

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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. 

7Presidential Memorandum—Power Sector 

Carbon Pollution Standards, June 25, 2013. http:// 

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

presidential-memorandum-power-sector-carbonpollution-standards. 

8See 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. 

2. How To Determine if a Unit Is 

Covered By an Approved and Effective 

State Plan 

Section 111(d) of the CAA, as 

amended, 42 U.S.C. 7411(d), authorizes 

the EPA to develop and implement a 

federal plan for affected EGUs upon the 

EPA’s action finding a failure to submit 

or disapproving a state plan.6 The 

affected EGUs covered in EPA-approved 

state plans are not subject to the federal 

plan. If the federal plan has been put in 

place in a state, but is later replaced by 

an EPA-approved state plan, the affected 

EGUs would become subject to the state 

plan as of the effective date specified in 

a Federal Register notice regarding the 

EPA’s approval of the state plan. The 

EPA is not expecting state plans to be 

submitted by the states that submit 

negative declarations. However, in the 

event that there are later determined to 

be affected EGUs located in these states, 

the final federal plan would be applied 

to such EGUs through a future action. 

Part 62 of title 40 of the CFR identifies 

the status of approval and promulgation 

of CAA section 111(d) state plans for 

designated facilities in each state. 

Recognizing the urgent need for actions 

to reduce GHG emissions, and in 

accordance with the Presidential 

Memorandum,7 as well as the benefit of 

providing states with model trading rule 

options to consider as they prepare their 

state plans, the EPA is proposing this 

rulemaking concurrently with the 

Administrator’s signing and 

promulgation of the final Clean Power 

Plan EGs. 40 CFR part 62 is updated 

only once per year. Thus, if 40 CFR part 

62 does not indicate that your state has 

an approved and effective plan after the 

compliance date has passed requiring 

state plan submittal, you should contact 

your state environmental agency’s Air 

Director or your EPA Regional Office 

(see Table 2 in section II.B of this 

preamble) to determine if approval 

occurred since publication of the most 

recent version of 40 CFR part 62. 

D. What should I consider as I prepare 

my comments? 

Do not submit information that you 

consider to be CBI electronically 

through http://www.regulations.gov or 

email. Send or deliver information 

identified as CBI to only the following 

address: OAQPS Document Control 

Officer (Room C404–02), U.S. EPA, 

Research Triangle Park, NC 27711, 

Attention Docket ID No. EPA–HQ– 

OAR–2015–0199. Clearly mark the part 

or all of the information that you claim 

to be CBI. For CBI on a disk or CD–ROM 

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 of this preamble. 

Docket. The docket number for the 

proposed action (40 CFR part 62, 

subpart MMM) is Docket ID No. EPA– 

HQ–OAR–2015–0199. 

World Wide Web (WWW). In addition 

to being available in the docket, an 

electronic copy of the proposed action 

is available on the Internet through the 

EPA’s Technology Transfer Network 

(TTN) Web site, a forum for information 

and technology exchange in various 

areas of air pollution control. Following 

signature by the EPA Administrator, the 

EPA will post a copy of the proposed 

action at http://www2.epa.gov/clean

powerplan/regulatoryactions#regulations. Following 

publication in the Federal Register (FR) 

the EPA will post the FR version of the 

proposed rule and key technical 

documents on the same Web site. 

II. Background Information 

A. What is the regulatory development 

background for this proposed rule? 

On August 3, 2015, the EPA finalized 

the Clean Power Plan EGs for existing 

fossil fuel-fired EGUs (40 CFR part 60, 

subpart UUUU) under authority of 

section 111 of the CAA (79 FR 34950). 

The Guidelines apply to existing fossil 

fuel-fired EGUs, i.e., those that were in 

operation or had commenced 

construction before January 8, 2014. 

States with existing EGUs subject to the 

EGs are required to submit to the EPA 

by September 6, 2016, a state plan that 

implements the EGs. States may also 

make initial plan submittals in lieu of a 

complete state plan, in which case 

extensions will be granted until 

September 6, 2018 (40 CFR part 60, 

subpart UUUU).8 As discussed in 

section VI.D of this preamble, Indian 

Tribes may, but are not required to, 

submit tribal plans. Once the EPA finds 

that a state has failed to submit a plan, 

or disapproves a state plan,9 section 111 

of the CAA and 40 CFR 60.27 require 

the EPA to develop, implement, and 

enforce a federal plan for existing EGUs 

located in that state. In addition, CAA 

section 301(d)(2) authorizes the 

Administrator to treat an Indian Tribe in 

the same manner as a state for this EGU 

requirement. See 40 CFR 49.3; see also 

‘‘Indian Tribes: Air Quality Planning 

and Management,’’ hereafter ‘‘Tribal 

Authority Rule,’’ (63 FR 7254, February 

12, 1998). As discussed in section VI.D 

of this preamble, the agency in this 

action is proposing a necessary or 

appropriate finding for the affected 

EGUs in several areas of Indian country 

and is proposing the federal plan for 

these affected EGUs. 

The agency believes it is appropriate 

to propose the federal plan at this time 

for any states that may ultimately be 

found to have failed to submit a plan, 

or had their plan disapproved by the 

EPA. For some states in this situation, 

the federal plan may be no more than 

an interim measure to ensure that 

congressionally mandated emission 

standards under authority of section 111 

of the CAA are implemented until they 

can get an approved plan in place. Other 

states may choose to rely on the 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 section 

II.B of this preamble. 

In this proposal, the EPA is soliciting 

public comment only on the proposed 

approaches for a federal plan and model 

trading rule for the implementation of 

the Clean Power Plan EGs. Comments 

on the underlying Clean Power Plan 

rule will be considered outside the 

scope for this proposed rule. 

B. What is the purpose of this proposed 

rule? 

The purpose of this action is two-fold: 

(1) To co-propose two approaches to a 

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10States may request extensions of up to two 

years as part of a complete initial CAA section 

111(d) submission. 

federal plan to implement the Clean 

Power Plan EGs for affected EGUs 

operating in any state lacking an 

approved state plan by the relevant 

deadlines; and (2) to propose these same 

approaches as model trading rules for 

states to consider in developing their 

own plans. 

1. Federal Plan 

Section 111 of the CAA and 40 CFR 

60.27 require the EPA to develop, 

implement and enforce a federal plan to 

cover existing EGUs located in states 

that do not have an approved plan. 

Section 111(d) of the CAA relies upon 

states as the preferred implementers of 

EGs for existing EGUs. States with 

affected EGUs are to submit state plans 

or make initial submittals to the EPA by 

September 6, 2016 pursuant to the 

EGs.10 States without any existing EGUs 

are directed to submit to the 

Administrator a letter of negative 

declaration certifying that there are no 

affected EGUs in the state. No plan is 

required for states that do not have any 

affected EGUs. Affected EGUs located in 

states that mistakenly submit a letter of 

negative declaration will become subject 

to the federal plan until a state plan 

covering those EGUs becomes approved. 

The EPA intends to finalize the federal 

plan only for those states that the EPA 

finds failed to submit plans or whose 

plans the EPA disapproves. For more 

information on the timing and 

mechanics of EPA action on state plans 

and finalization of this federal plan, see 

section II.D of this preamble below. 

2. Model Trading Rule 

The EPA is also proposing the federal 

plan approaches as two forms of a 

model trading rule (mass-based and 

rate-based), which states can adopt or 

tailor for implementation as a state plan 

under the EGs. The EPA intends to 

finalize the model trading rules earlier 

than it promulgates a federal plan for a 

state. When the EPA finalizes one or 

both of its proposed approaches as a 

final model trading rule, and a state 

adopts a final model trading rule in its 

entirety as its state plan, it would be 

presumptively approvable. 

The EPA has designed these rules so 

that they meet the requirements of the 

final EGs. If one of the model rules is 

adopted by a state without any change, 

it would be presumptively approvable. 

We use the term ‘‘presumptively’’ in 

recognition that a state plan submission 

must be accompanied by other materials 

in addition to the regulatory provisions. 

These requirements are set forth in the 

final Clean Power Plan and framework 

regulations of 40 CFR part 60, subpart 

B. For instance, they include a formal 

letter of submittal from the Governor or 

his or her designee, evidence that the 

rule has been adopted into state law and 

that the state has necessary legal 

authority to implement and enforce the 

rule, and evidence that procedural 

requirements, including public 

participation under 40 CFR 60.23, have 

been met. 

In further support of state use of the 

model rules, we are drafting the model 

trading rule so that it can be adopted or 

incorporated by reference with a 

minimum of changes that would be 

necessary to make the rule appropriate 

for use by states. This way, a state may 

incorporate by reference the model rule 

as the state plan, or as the backstop to 

a state measures plan with few if any 

adjustments. States may make changes 

to the model trading rule, so long as 

they still meet the requirements of the 

EGs. If the state chooses to tailor or 

modify the model trading rule such as 

by expanding the scope of eligibility of 

projects that may generate ERCs in a 

rate-based trading program, the EPA 

may still approve the plan, but the EPA 

would conduct appropriate review of 

such provisions for consistency with the 

EGs and the state would have to 

demonstrate to the EPA’s satisfaction 

that its alternative provisions are as 

stringent as the presumptively 

approvable approach described. We 

note here, and in the regulatory text of 

the model trading rule, that the scope of 

eligibility of proposed ‘‘ERC resources’’ 

for the federal plan is different than the 

scope of eligibility provided for in the 

model rule. Thus, all of the language 

and provisions in the regulatory text 

relevant to these other ERC resources is 

relevant only to the proposed model 

trading rule and not to the federal plan 

as such (i.e., those ERC resources 

discussed in section IV.C.3 of this 

preamble are applicable to the model 

rule and only metered RE and 

applicable nuclear are applicable to the 

federal plan). 

The EPA’s approval of a state plan, 

including a plan that adopts the model 

trading rule, will be the result of an 

independent notice-and-comment 

rulemaking process. Without prejudging 

the outcome of that process, the EPA 

recognizes that it may be able to 

approve or ‘‘conditionally approve’’ 

state plans that are substantially similar, 

but not identical to, the final model 

trading rules. Ultimately, state plans 

must meet the requirements of the EGs 

for approvability. Thus, a conditional 

approval would be based on a condition 

that the state take such actions as may 

be necessary by a date certain to meet 

the requirements of the EGs. (The EPA 

is proposing to explicitly provide for 

conditional approvals in the CAA 

section 111(d) framework regulations. 

See section VII.B of this preamble.) 

In accordance with the EGs, the 

process for review and approval (or 

disapproval) of state plans, whether 

based on the model trading rules or 

otherwise, would occur once the states 

have made their submissions by 

September 6, 2016. As provided in the 

EGs, states have the option of not 

submitting a full state plan, but rather 

making an initial submittal, in order to 

obtain an extension of 2 years before 

submitting a full state plan for EPA 

approval. It could be beneficial for 

coordination purposes if a state that is 

interested in adopting one of the model 

trading rules but intends to make an 

initial submittal next year were to 

indicate which model trading rule they 

intend to adopt. This is not an 

additional requirement beyond what the 

EGs require for initial submittals, 

however. 

The EPA strongly encourages states to 

consider adopting one of the model 

trading rules, which are designed to be 

referenced by states in their 

rulemakings. Use of the model trading 

rules by states would help to ensure 

consistency between and among the 

state programs, which is useful for the 

potential operation of a broad trading 

program that spans multi-state regions 

or operates on a national scale. As 

discussed at length in the EGs, EGUs 

operate less as individual, isolated 

entities and more as multiple 

components of a large interconnected 

system designed to integrate a range of 

functions that ensure an uninterrupted 

supply of affordable and reliable 

electricity while also, for the past 

several decades, maintaining 

compliance with air pollution control 

programs. Since, as a practical matter 

under both the EGs and any federal 

plan, emission reductions must occur at 

the affected EGUs, a broad-scale 

emissions trading program would be 

particularly effective in allowing EGUs 

to operate in a way that achieves 

pollution control without disturbing the 

overall system of which they are a part 

and the critical functions that this 

system performs. In addition, 

consistency of requirements benefits the 

affected EGUs, as well as the states and 

the EPA in their roles as administrators 

and implementers of a trading program. 

States of course remain free to develop 

a plan of their own choosing to submit 

to the EPA for approval following the 

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11We also note that historically under the CAA 

section 111(d)/129 rules, the content of EGs and 

their corresponding federal plans have had 

significant overlap. 

12We 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. 

13 Indeed, states may simply choose to accept a 

federal plan in lieu of undertaking to develop a 

state plan at all. While the statute uses the phrase 

‘‘fails to submit a satisfactory plan,’’ the EPA does 

not believe this should carry any pejorative 

connotation. While Congress identified states and 

local governments as having ‘‘primary 

responsibility’’ for air pollution prevention and 

control, CAA section 101(a)(3), states are in no way 

penalized for not submitting a plan under CAA 

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

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

program in its stead. To the extent states may be 

interested in accepting a federal plan, the EPA 

would be interested in hearing that through the 

comment process on this proposal. 

14We anticipate that the model rules’ text could 

be finalized either in a new subpart or subparts of 

40 CFR part 62 of title 40 of the CFR as proposed, 

or in a final document that is not published in the 

CFR. 

criteria set out in the final Clean Power 

Plan EGs. 

The EPA believes there are 

compelling policy reasons that support 

the provision of a proposed model 

trading rule at this time. The EPA has 

heard from multiple stakeholders and in 

public comments submitted on the 

proposed EGs that there is a strong 

interest in seeing a model state plan or 

trading rule prior to the deadline for 

state submittals under the EGs. 

According to these stakeholders, model 

rules can provide predictability for 

planning purposes, both among states 

and affected EGUs. In addition, some 

states have indicated that they may 

prefer to rely on a federal plan, either 

temporarily or permanently, rather than 

develop a plan of their own. This 

proposal of a model trading rule 

addresses these policy interests. 

The approach of proposing model 

trading rules that are identical in all key 

respects to proposed federal plans that 

may be promulgated later, is consistent 

with prior CAA section 111(d) and CAA 

section 110 rulemakings. For example, 

the NOX state implementation plan (SIP) 

Call model rule at 40 CFR part 96 (63 

FR 57356; October 27, 1998) was 

identical in all meaningful respects with 

the Federal NOX Budget Trading 

Program at 40 CFR part 97 (65 FR 2674; 

January 18, 2000). And the CAIR model 

rule in 40 CFR part 96 (70 FR 25339; 

May 12, 2005) was identical in all 

meaningful respects with the federal 

CAIR in 40 CFR part 97 (71 FR 25396; 

April 28, 2006).11 While these identical 

programs for model rules and Federal 

Implementation Plans (FIPs) were 

finalized in separate parts of the CFR, 

the EPA does not see any reason that it 

could not just as easily propose the 

federal plan as the model trading rule in 

the same section of the CFR.12 If a 

federal plan were to be finalized for a 

given state at a later time, this would be 

reflected in 40 CFR part 62 by crossreference, along with any modifications 

or adjustments that may be appropriate 

at the time of actual promulgation of a 

federal plan. 

TABLE 2—REGIONAL OFFICE CONTACTS

Region Regional contact Phone States and protectorates 

Region I ......... Shutsu Wong, wong.shutsu@epa.gov .......... 617–918–1078 Connecticut, Massachusetts, Maine, New Hampshire, 

Rhode Island, Vermont. 

Region II ........ Gavin Lau, lau.gavin@epa.gov ..................... 212–637–3708 New York, New Jersey, Puerto Rico, Virgin Islands. 

Region III ....... Mike Gordon, gordon.mike@epa.gov ........... 215–814–2039 Virginia, Delaware, District of Columbia, Maryland, Pennsylvania, West Virginia. 

Region IV ....... Ken Mitchell, mitchell.ken@epa.gov ............. 404–562–9065 Florida, Georgia, North Carolina, Alabama, Kentucky, Mississippi, South Carolina, Tennessee. 

Region V. ....... Alexis Cain, cain.alexis@epa.gov ................. 312–886–7018 Minnesota, Wisconsin, Illinois, Indiana, Michigan, Ohio. 

Region VI ....... Rob Lawrence, lawrence.rob@epa.gov ........ 214–665–6580 Arkansas, Louisiana, New Mexico, Oklahoma, Texas. 

Region VII ...... Ward Burns, burns.ward@epa.gov ............... 913–551–7960 Iowa, Kansas, Missouri, Nebraska. 

Region VIII ..... Laura Farris, farris.laura@epa.gov ............... 303–312–6388 Colorado, Montana, North Dakota, South Dakota, Utah, 

Wyoming. 

Region IX ....... Ray Saracino, saracino.ray@epa.gov ........... 415–972–3361 Arizona, California, Hawaii, Nevada, American Samoa, 

Guam, Northern Mariana Islands. 

Region X ........ Dan Brown, brown.dan@epa.gov ................. 503–326–6823 Alaska, Idaho, Oregon, Washington. 

C. Legal Authority 

Section 111(d)(2) of the CAA, 42 

U.S.C. 7411(d)(2) provides the EPA the 

same authority to prescribe a plan for a 

state in cases where the state fails to 

submit a satisfactory plan as the agency 

would have under CAA section 110(c) 

in the case of failure to submit an 

implementation plan. In addition, the 

EPA has authority under CAA section 

111(d)(1) to prescribe regulations that 

establish procedures similar to CAA 

section 110 with respect to the 

submission of state plans, and the EPA 

also has general rulemaking authority as 

necessary to implement the CAA under 

CAA section 301. A federal plan under 

CAA section 111(d) applies, implements 

and enforces standards of performance 

for affected EGUs. Under the Clean 

Power Plan EGs, state plans will be due 

on September 6, 2016, but states are also 

allowed to seek a 2-year extension for a 

final plan submittal, upon a satisfactory 

initial plan submittal by the same 

deadline. See 40 CFR 60.5755, 

60.5760(b). If a state does not submit a 

final state plan or initial plan 

submittal,13 or if either a final state plan 

or an initial plan submittal does not 

meet the requirements of the EG, the 

agency will take the appropriate steps to 

finalize and implement a federal plan 

for that state’s EGUs. 

Further, states will remain free, and 

indeed are strongly encouraged, to 

submit an approvable state plan even 

after promulgation of the federal plan 

for their jurisdictions. The EPA will 

withdraw the federal plan for a state 

when that state submits, and the EPA 

approves, a final plan. See 40 CFR 

60.5720. 

D. Timing of EPA Actions on the Model 

Trading Rules, Federal Plan, and Other 

Proposed Actions 

This action co-proposes two 

approaches to the federal plan, both of 

which also constitute proposed model 

trading rules that states could adopt as 

state plans for EPA approval. The EPA 

currently intends to finalize one or both 

of the model trading rules by next 

summer so that they may be available to 

states as soon as possible to help inform 

their state plan development efforts 

prior to the initial submittal deadline of 

September 6, 2016, and 2 years before 

the states’ final plan deadline of 

September 6, 2018.14 If the EPA 

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15The 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). 16We 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 October 21, 2014) (upholding use of 

backstop cap-and-trade program under 40 CFR 

41.309 of the Regional Haze Rule). 

finalizes the model trading rules in that 

timeframe, the only direct consequence 

will be to provide the states certainty as 

to one or two particular approaches to 

the design of their state plan that the 

EPA will approve if adopted in full. The 

finalization of a model trading rule will 

not constitute a final action with respect 

to a federal plan for the affected EGUs 

in any state. Rather, the proposed 

federal plan will remain just that, a 

proposal. The EPA will promulgate a 

final federal plan for any state only after 

it has made a finding on a state’s failure 

to submit a plan, or fully or partially 

disapproved a submitted state plan. The 

EPA will go through a public notice and 

comment process before disapproving a 

submitted and complete state plan, in 

whole or part. The EPA invites 

comments on this staged approach to 

finalizing one or more model trading 

rules on the one hand (which we 

currently intend to do in summer 2016), 

and finalizing federal plans on the other 

(which we currently intend to do stateby-state upon our taking predicate 

action on states’ plans). 

In this action, the EPA is also 

proposing enhancements to the process 

for agency action on state submittals 

and promulgation of a federal plan 

under CAA section 111(d). For more 

detailed discussion of these changes, see 

section VII of this preamble. This aspect 

of this proposal is separate from the 

federal plan and the model trading 

rules. The EPA intends to finalize these 

changes on a timeline earlier than both 

a model trading rule and the federal 

plan. 

Under the framework regulations as 

proposed to be amended, see section VII 

below, and the final EGs, at 40 CFR 

60.27 and 60.5715 and 5760, 

respectively, the initial timelines for 

EPA action on state submittals and, 

potentially, the promulgation of a 

federal plan will be as follows: The EPA 

will have 12 months from the date of a 

state’s submission to approve or 

disapprove that state’s plan. The EPA 

will have 12 months from the date of its 

action on a state submission to 

promulgate the federal plan for the 

EGUs in that state. Under the 

completeness-criteria process proposed 

to be added to 40 CFR 60.27, see section 

VII.E below, the EPA would have 6 

months from the deadline for 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 40 CFR 60.5765, the 

EPA will have 90 days from the date the 

EPA received the initial submittal to 

notify a state that its initial submittal 

does not meet the requirements of 40 

CFR 60.5765(a). As with state plans, the 

EPA will have 12 months to promulgate 

a federal plan from the date of its 

finding that a state failed to submit a 

complete and approvable initial 

submittal. (Formally, such a finding 

would be that the state failed to submit 

a state plan.) 

The timeframes stated in the previous 

paragraph reflect the maximum time 

allowed for EPA action. We note that 

under CAA section 111(d)(2) and CAA 

section 110(c), the EPA may promulgate 

a final federal plan for a state 

immediately upon making a finding of 

failure to submit a state plan or initial 

submittal, or upon making a finding of 

final disapproval of a state plan. 

Congress gave the EPA authority in CAA 

section 111(d)(2), as it did in CAA 

section 110(c), to promulgate a federal 

plan at any time after it disapproves or 

finds a failure to submit a state plan. 

The Supreme Court has recognized that 

under this authority, the EPA may 

promulgate a FIP ‘‘at any time’’ within 

the 2-year limit of CAA section 110(c) 

‘‘that begins the moment EPA 

determines a SIP to be inadequate.’’ 

EME Homer City v. EPA, 134 S. Ct. 1584, 

1601 (2014). ‘‘EPA is not obliged to wait 

two years or postpone its action even a 

single day . . . .’’ Id. It is essential to 

implement plans for the control of 

emissions of CO2 expeditiously and 

avoid unnecessary delay. Among other 

reasons, this will provide affected EGUs 

regulatory certainty and will assist the 

regulated entities as well as those 

authorities with responsibility for 

ensuring grid reliability to have as much 

time as possible to plan for the 2022 

compliance start date set in the EGs. 

Thus, it is reasonable to propose this 

federal plan now so that federal plans 

will be ready to be promulgated quickly 

in cases where states have failed to 

submit a plan or their plans are found 

unsatisfactory. 

It is the agency’s intention to 

promulgate federal plans promptly for 

states who do not submit plans or initial 

submittals by September 6, 2016. 

However, the effect of putting the 

federal plan in place at that time would 

ultimately be limited in impact upon 

states. Because the EPA would 

implement the federal plan, its 

promulgation does not obligate state 

officials to take any actions themselves. 

Further, states remain free—and the 

EPA in fact encourages states—to 

submit state plans that can replace the 

federal plan. States can do so in advance 

of the beginning of the performance 

period in 2022, or may transfer to a state 

plan after that date. However, in doing 

so, the agency and states should be 

mindful of the goals of regulatory 

certainty discussed in the prior 

paragraph. 

Because we are proposing a federal 

plan that would apply emission 

standards to affected EGUs in all states 

that the agency determines not to have 

an approvable plan, the EPA invites 

comment from all persons with 

concerns about or comments on the 

proposed federal plan as it may apply in 

any state, whether or not that state has 

submitted, or intends to submit, its own 

plan on which the EPA has yet to take 

action. 

In this document, the EPA is 

proposing regulatory text setting out the 

substantive provisions for both of the 

proposed federal plans/model trading 

rules. The EPA is not providing specific 

regulatory text that would, if finalized, 

actually promulgate a federal plan for 

each state for which this proposed 

federal plan might be applied.15 We 

currently envision that this language 

would be in the form of a new section 

to the state-specific subparts of part 62 

and would be ministerial in nature. It 

would likely provide that the affected 

EGUs in each such state are subject to 

a federal plan and would then crossreference or incorporate by reference the 

substantive provisions of one of the two 

subparts proposed in this action (if 

finalized), along with any applicable 

modifications or adjustments as may be 

necessary, either based on new 

information or in response to comments 

regarding the application of the federal 

plan to that particular state. This text 

may appear similar to the FIP language 

found in the final CSAPR rule (76 FR 

48208, 48361–78; August 8, 2011). 

E. Use of the Model Trading Rule as a 

Backstop 

As discussed in the final EGs, the EPA 

believes that either a mass-based or ratebased model trading rule could function 

well as the federally enforceable 

‘‘backstop’’ that the EGs require to be 

included in ‘‘state measures’’ type state 

plans.16 (The proposed federal plan 

does not itself require a ‘‘backstop’’ 

because it relies on an ‘‘emission 

standards’’ approach, rather than a 

‘‘state measures’’ approach, as 

delineated in the final EGs.) The 

conditions and requirements for the 

federally enforceable backstop in a state 

measures approach are discussed in 

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

State officials responsible for developing state 

plans, however, should be aware of the procedural 

enhancements being proposed to the framework 

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

rulemaking document. These changes are discussed 

in section VII of this preamble below. These 

changes are not a component of the proposed 

federal plan or the EGs. Although these changes do 

not alter the deadlines or submission obligations 

provided in the Clean Power Plan Emission 

Guidelines, state officials and other interested 

parties are encouraged to review and comment on 

these changes. 

detail in the final EGs. See sections 

VIII.C.3.b and VIII.C.6.c of the final EGs. 

To summarize those provisions, without 

reopening them for comment, the 

federally enforceable backstop must 

fully achieve the CO2 emission 

performance rates or the state’s interim 

and final CO2 emission goals if the state 

plan fails to achieve the intended level 

of CO2 emission performance. The state 

plan submittal must identify the 

federally enforceable emission 

standards for affected EGUs that would 

be used in the backstop, demonstrate 

that those emission standards meet the 

requirements that apply in the context 

of an emission standards approach, 

identify a schedule and trigger for 

implementation of the backstop that is 

consistent with the requirements in the 

EGs, and identify all necessary state 

administrative and technical procedures 

for implementing the backstop (e.g., 

how and when the state would notify 

affected EGUs that the backstop has 

been triggered). In addition, the 

backstop emission standards must make 

up for any shortfall in CO2 emission 

performance during a prior plan 

performance period that led to triggering 

of the backstop. 

The EGs explicitly recognized that the 

backstop emission standards could be 

based on one of the model trading rules 

that the EPA is proposing in this action. 

As discussed in section II.B of this 

preamble above, we are drafting the 

model trading rule so that it can be 

adopted or incorporated by reference 

with a minimum of changes necessary 

to make the rule appropriate for use by 

states, and this includes its use as a 

backstop. Instances of this approach are 

throughout the proposed rule text and 

reflect our desire to ease the use of the 

model rule for states, as a full state plan, 

or as a backstop to a ‘‘state measures’’ 

plan. 

One way in which a backstop may 

need to differ from the model trading 

rules proposed in this action is the 

requirement to make up for a shortfall 

in emissions performance in a state’s 

prior plan performance period. The 

model trading rules do not provide 

provisions that would automatically 

adjust the emission standards to account 

for any prior emission performance 

shortfall (which is an option states have 

if designing their own backstop). Thus, 

a state relying on the model trading rule 

as its backstop would likely need to 

submit an appropriate revision to the 

backstop emission standards adjusting 

for the shortfall through the state plan 

revision process. This would likely be 

done in conjunction with the process for 

putting the backstop into effect. 

If a state chooses to use the model 

rule as its federally enforceable backstop 

in a state measures plan, this does not 

mean that the backstop is itself the 

federal plan. Rather, the model rule 

becomes adopted as a part of the state 

plan. Both approaches to the model 

trading rule are ‘‘emission standard’’ 

approaches under the EGs where an 

emission standard is imposed and 

federally enforceable on the affected 

EGUs: In the rate-based approach the 

emissions standard is an allowable rate 

of emissions; in the mass-based 

approach the emission standard is the 

requirement to hold allowances equal to 

reported emissions. The EPA may also 

handle the administration of the trading 

program for states utilizing the model 

trading rule. However, even though the 

backstop may take the form of an EPAadministered, federally-enforceable 

trading rule, this does not mean that a 

federal plan has been put into effect. 

The state retains all of its rights and 

responsibilities with respect to the 

implementation and enforcement of the 

backstop as a component of its state 

plan. 

Applicability and Enforceability. If 

promulgated for the affected EGUs in a 

particular state, this federal plan will 

require affected EGUs to meet specific 

emission standards for CO2 and related 

requirements. These enforceable 

compliance obligations will apply to the 

owners and operators of those affected 

EGUs. See 40 CFR 62.13. No obligation 

falls on states or state officials (except 

to the extent they may be owners and 

operators of affected EGUs).17 In the 

event of noncompliance, the provisions 

in the federal plan are federally 

enforceable against an affected EGU, in 

the same manner as the provisions of an 

approved state plan under CAA section 

111(d), and similar to a FIP or an 

approved SIP under CAA section 110. 

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

7411(d)(2)(B) (power to enforce state 

and federal plans), section 113(a)–(h), 

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

42 U.S.C. 7604. This means that the 

Administrator has the ability to enforce 

against violations and secure 

appropriate corrective actions pursuant 

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

and other third parties maintain the 

ability to enforce against violations and 

secure appropriate corrective actions 

pursuant to CAA section 304. 

III. Federal Plan Structure To Achieve 

Reductions 

A. Overview 

1. Interactions With State Plans and 

Scope of Trading 

The EPA intends to set up and 

administer a program to track trading 

programs—both rate-based and massbased—that will be available for all 

states that choose it. The EPA proposes 

that affected EGUs in any state covered 

by a federal plan could trade 

compliance instruments with affected 

EGUs in any other state covered by a 

federal plan or a state plan meeting the 

conditions for linkage to the federal 

plan. In the proposed mass-based 

federal plan trading program, this would 

mean that affected EGUs in a state 

covered by the federal plan or a state 

meeting the conditions for linkage to the 

federal plan could use, as a compliance 

instrument, an allowance distributed in 

any other state covered by the federal 

plan or a state meeting the conditions 

for linkage to the federal plan. Similarly, 

in the proposed rate-based federal plan 

trading program approach, this would 

mean that affected EGUs in a state 

covered by the federal plan or a state 

meeting the conditions for linkage to the 

federal plan could use, as a compliance 

instrument, an ERC issued in any other 

state covered by the federal plan or a 

state meeting the conditions for linkage 

to the federal plan. We propose that an 

affected EGU in a state covered by the 

mass-based trading federal plan must 

use allowances for compliance (not 

ERCs). Similarly, an affected EGU in a 

state covered by the rate-based trading 

federal plan must use ERCs for 

compliance (not allowances). 

The agency promulgated provisions 

for ‘‘ready-for-interstate-trading’’ plans 

in the EGs. The EPA is proposing the 

federal plans as ready-for-interstatetrading plans. State plans that adopt the 

model rule are also considered readyfor-interstate-trading. The EPA proposes 

to allow interstate trading between 

affected EGUs in states covered by the 

proposed federal plans and affected 

EGUs in states covered by state plans 

(referred to below as ‘‘linking’’ states, or 

‘‘linkages’’) under the following 

conditions, which are discussed further 

below the list: 

• The state plan must be approved. 

• The state plan must implement the 

same type of trading program as the 

federal plan trading program in order to 

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18 In this preamble all references to ‘‘tons’’ are 

short tons, unless otherwise noted. 

be linked for interstate trading, i.e., 

mass-based trading programs can link to 

mass-based trading programs only, and 

rate-based trading programs can link to 

rate-based trading programs only. 

• The state plan must use the 

identical compliance instrument as the 

federal plan (this requirement is 

detailed below). 

• The state plan must be approved as 

a ready-for-interstate-trading plan. 

• The state plan must use an EPAadministered tracking system (we are 

also requesting comment on expanding 

this to include a state plan that uses an 

EPA-designated tracking system that is 

interoperable with an EPA-administered 

system, as detailed below). 

The EPA proposes that interstate ERC 

trading could occur both (1) from 

affected EGUs in states covered by the 

rate-based trading federal plan to 

affected EGUs in states with approved 

rate-based trading state plans meeting 

the proposed conditions for linkages 

(including the conditions for being 

‘‘ready-for-interstate-trading’’ that were 

finalized in the EG), and (2) from 

affected EGUs in such state-plancovered states to affected EGUs in 

federal-plan-covered states. The EPA 

also requests comment on expanding 

the scope of interstate trading to include 

linking states covered by the rate-based 

trading federal plan with any state that 

has an approved rate-based trading state 

plan meeting the proposed conditions 

for linkages and that uses an EPAdesignated ERC tracking system that is 

interoperable with an EPA-administered 

ERC tracking system. The EPA also 

requests comment on allowing a state 

that has an approved rate-based trading 

state plan meeting the proposed 

conditions for linkages and that uses an 

EPA-designated ERC tracking system to 

register with the EPA, and after 

registration, to link with states covered 

by the rate-based trading federal plan. 

There are multiple benefits to a 

registration requirement, which include 

ensuring that the tracking systems are 

functionally interoperable. 

For the mass-based federal plan, the 

EPA proposes that interstate allowance 

trading could occur in both directions, 

i.e., from affected EGUs in states 

covered by the mass-based trading 

federal plan to affected EGUs in states 

with approved mass-based trading state 

plans meeting the proposed conditions 

for linkages, and from affected EGUs in 

such state-plan-covered states to sources 

in federal-plan-covered states. 

The EPA proposes that a condition of 

linkage between a state plan and the 

federal plan is the use of an identical 

compliance instrument. In the massbased federal plan the EPA proposes to 

issue allowances in short tons; as a 

result, the EPA is proposing in this rule 

that linkage for the mass-based federal 

plan is limited to state plans that issue 

allowances in short tons. The agency 

also requests comment on whether to 

extend linkage to state plans that issue 

allowances in metric tons and on what 

provisions would be necessary to 

implement such linkages. The EPA 

believes that considerations for linkages 

to state plans that use metric tons may 

include tracking system design, and 

stipulation of which parties convert 

state plan allowances denominated in 

metric tons to allowances denominated 

in short tons and at what stage of 

compliance operations the conversion 

occurs. The agency requests comment 

on these and any other considerations 

for linkages between the federal plan 

and state plans that issue allowances in 

metric tons.18

The EPA also requests comment on 

expanding the scope of interstate 

trading to include linking states covered 

by the mass-based trading federal plan 

with any state that has an approved 

mass-based trading state plan meeting 

the proposed conditions for linkages 

and that uses an EPA-designated 

allowance tracking system that is 

interoperable with an EPA-administered 

allowance tracking system. The EPA 

also requests comment on allowing a 

state that has an approved mass-based 

trading state plan meeting the proposed 

conditions for linkages and that uses an 

EPA-designated allowance tracking 

system to register with the EPA, and 

after registration, to link with states 

covered by the mass-based trading 

federal plan. 

In the Clean Power Plan EGs, the EPA 

promulgated requirements that apply to 

an emissions budget trading state plan 

that includes non-affected EGU 

emission sources, to provide the 

opportunity for such a state plan to be 

potentially approvable for linking to 

other state plans (see Clean Power Plan 

EGs, section VIII). In this proposed rule, 

the proposed approach to link from the 

mass-based trading federal plan to state 

plans could result in linking of the 

federal plan to state plans that include 

non-affected emission sources. The EPA 

requests comment on this proposed 

approach. 

The EPA believes that a broad trading 

region provides greater opportunities for 

cost-effective implementation of 

reductions compared to trading limited 

to a smaller region. The proposed 

approach to interstate trading is 

intended to strike a reasonable balance 

between providing the opportunity for a 

wide interstate trading system while 

maintaining the integrity of the linked 

programs. The agency requests comment 

on the proposed approach to interstate 

trading linkages in the federal plans. 

Whether the EPA ultimately finalizes 

rate-based or mass-based federal plans, 

the agency believes that the ERC market 

and the allowance market would be 

competitive. The opportunities for 

interstate trading detailed above would 

reduce any potential for firms to 

exercise market power in the ERC 

market or allowance market. The EPA 

requests comment on this expectation of 

a competitive ERC market and a 

competitive allowance market, and 

comment on potential program design 

choices that could address any 

identified market power concern. The 

EPA intends to provide information to 

the market and the public, consistent 

with other trading programs that the 

agency administers, as detailed in 

sections IV and V of this preamble, for 

the rate-based and mass-based 

approaches, respectively. 

A transparent and well-functioning 

allowance or ERC market is an 

important element of a mass-based or 

rate-based trading program. The EPA 

has over 20 years of experience 

implementing emissions trading 

programs for the power sector and based 

on that experience, believes the 

potential or likelihood of market 

manipulation is fairly low. Nonetheless, 

the EPA is evaluating the options for 

providing oversight of the allowance or 

ERC markets that may be established 

through the final EGs and federal plans. 

This could include engaging with other 

federal and state agencies as 

appropriate, and potentially with third 

parties, in conducting market oversight. 

The agency requests comment on 

appropriate market monitoring 

activities, which may include tracking 

ownership of allowances or ERCs, 

oversight of the creation and verification 

of credits, and tracking market activity 

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

2. Addressing Potential Leakage and 

Interstate Effects 

The final EGs specify the concern of 

leakage, which is defined in section 

VII.D of the final EGs as the potential of 

an alternative form of implementation of 

the BSER (e.g., the rate-based and massbased state goals) to create a larger 

incentive for affected EGUs to shift 

generation to new fossil fuel-fired EGUs 

relative to what would occur when the 

implementation of the BSER took the 

form of standards of performance 

incorporating the subcategory-specific 

emission performance rates representing 

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19 ‘‘Inventory of U.S. Greenhouse Gas Emissions 

and Sinks: 1990–2013’’, Report EPA 430–R–15–004, 

United States Environmental Protection Agency, 

April 15, 2015. http://www.epa.gov/climatechange/ 

ghgemissions/usinventoryreport.html. 

20U.S. EPA Greenhouse Gas Reporting Program 

Dataset, see http://www.epa.gov/ghgreporting/

ghgdata/reportingdatasets.html. 

21Sinks are a physical unit or process that stores 

GHGs, such as forests or underground or deep sea 

reservoirs of CO2. 

the BSER. The final EGs specified that 

mass-based plan approaches must 

address leakage, because the form of the 

mass goals may ultimately impact the 

relative incentives to generate and emit 

at affected EGUs as opposed to shifting 

generation to new sources, with 

potential implications for whether the 

mass goal implements or is consistent 

with the BSER and overall emissions 

from the sector. These circumstances are 

much less likely to be present under a 

rate-based plan approach, where the 

form of the goal ensures sufficient 

incentive to affected existing EGUs to 

generate and thus avoid leakage, similar 

to the CO2 emission performance rates. 

By requiring mass-based plan 

components that address leakage, the 

final EGs ensure that mass goals are 

equivalent to the CO2 emission 

performance rates and are thus an 

equivalent expression of the BSER. 

Section VII.D of the final EGs details the 

requirement for addressing leakage and 

why it is needed, and section VIII.J of 

the final EGs specifies options for massbased state plan components that 

address leakage. We are proposing, as 

part of the mass-based approach under 

the federal plan and model rule, to 

implement allowance allocation 

approaches to address leakage, 

specifically through establishing an 

output-based allocation set-aside and a 

set-aside that encourages the installation 

of RE. These proposed strategies are 

detailed in section V.D of this preamble. 

In the final EGs, the EPA also 

discussed the concern that CO2

emission reductions would be eroded in 

situations where an affected EGU in a 

rate-based state counts the MWh from 

measures located in a mass-based state, 

but the generation from that measure 

acts solely to serve load in the massbased state. In that scenario, expected 

CO2 emission reduction actions in the 

rate-based state are foregone as a result 

of counting MWh that resulted in CO2

emission reductions in a mass-based 

state. The proposed rate-based 

approach, in accordance with the final 

EGs, restricts ERC issuance for any 

emission reduction measures located in 

a mass-based state, except for RE. RE 

measures located in a state with a massbased 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 load-serving entities 

in the rate-based state have contracted 

for the delivery of the RE generation that 

occurs in a mass-based state to meet 

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

federal plan, we are proposing that this 

can be demonstrated through the 

provision of a power delivery contract 

or power purchase agreement in which 

an entity in the rate-based state 

contracts for the supply of the MWhs in 

question and providing documentation 

that the electricity was treated as 

comparable to a generation resource 

used to serve regional load that 

included the rate-based state. This 

demonstration must be included as part 

of the project application for ERC 

issuance to the EPA or its agent from the 

RE provider in the mass-based state. 

Once the project is approved, 

subsequent applications for issuance of 

credit to the EPA will need to reference 

that the MWh submitted are associated 

with that contractual arrangement with 

the mass-based RE provider. The EPA 

requests comment on this approach. It 

should also be noted that we are 

proposing that under the proposed 

mass-based approach, if RE located in a 

mass-based state receives mass-based 

set-aside allowances for any generation, 

that generation is not eligible to be 

issued ERCs in a rate-based state. 

The EPA requests comment on the 

proposed treatment of leakage and of 

interstate effects under both the 

proposed rate-based federal plan 

approach and the proposed mass-based 

federal plan approach, and as part of the 

corresponding proposed model rules. 

3. Provisions To Encourage Early Action 

The EPA outlined and initiated the 

CEIP in the final EGs (see section 

VIII.B.2 of the final EGs). The program 

is designed to incentivize investment in 

certain types of RE projects, as well as 

demand-side energy efficiency (EE) 

projects implemented in low-income 

communities. These RE projects must 

commence construction, and these EE 

projects must commence 

implementation after the date of 

submission of a final plan to the EPA by 

the state they are located on or 

benefitting, or after September 6, 2018 

for those states on whose behalf the EPA 

is implementing the federal plan, and 

will receive incentives for the MWh 

they generate or the end-use energy 

demand reductions they achieve during 

2020 and/or 2021. The CEIP also 

provides an additional incentive to 

drive investment in demand-side EE 

projects implemented in low-income 

communities. The EPA proposes to 

apply the CEIP in all states subject to 

either a rate-based or mass-based federal 

plan. The EPA’s proposed approaches to 

implementing the program in the ratebased and mass-based federal plans are 

detailed in sections IV and V of this 

preamble, respectively. 

B. Inventory of Emissions 

Fossil fuel-fired EGUs are by far the 

largest emitters of GHGs among 

stationary sources in the United States, 

primarily in the form of CO2, and among 

fossil fuel-fired EGUs, coal-fired units 

are by far the largest emitters. This 

section describes the amounts of these 

emissions and places these amounts in 

the context of the U.S. Inventory of 

Greenhouse Gas Emissions and Sinks 19

(the U.S. GHG Inventory). 

The EPA implements a separate 

program under 40 CFR part 98 called 

the Greenhouse Gas Reporting 

Program 20 (GHGRP) that requires 

emitting facilities over threshold 

amounts of GHGs to report their 

emissions to the EPA annually. Using 

data from the GHGRP, this section also 

places emissions from fossil fuel-fired 

EGUs in the context of the total 

emissions reported to the GHGRP from 

facilities in the other largest-emitting 

industries. 

The EPA prepares the official U.S. 

GHG Inventory to comply with 

commitments under the United Nations 

Framework Convention on Climate 

Change (UNFCCC). This inventory, 

which includes recent trends, is 

organized by industrial sectors. It 

provides the information in Table 3 of 

this preamble, which presents total U.S. 

anthropogenic emissions and sinks 21 of 

GHGs, including CO2 emissions, for the 

years 1990, 2005, and 2013. 

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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Proposed Rules 64979 

22From Table ES–4 of ‘‘Inventory of U.S. 

Greenhouse Gas Emissions and Sinks: 1990–2013’’, 

Report EPA 430–R–15–004, United States 

Environmental Protection Agency, April 15, 2015. 

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

usinventoryreport.html. 23The energy sector includes all greenhouse gases 

resulting from stationary and mobile energy 

activities, including fuel combustion and fugitive 

fuel emissions. 

24From Table ES–2 ‘‘Inventory of U.S. 

Greenhouse Gas Emissions and Sinks: 1990–2013’’, 

Report EPA 430–R–15–004, United States 

Environmental Protection Agency, April 15, 2015. 

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

usinventoryreport.html. 25From Table 3–1 ‘‘Inventory of U.S. Greenhouse 

Gas Emissions and Sinks: 1990–2013’’, Report EPA 

430–R–15–004, United States Environmental 

Protection Agency, April 15, 2015. http://www.epa.

gov/climatechange/ghgemissions/ 

usinventoryreport.html. 

26From Table 3–5 ‘‘Inventory of U.S. Greenhouse 

Gas Emissions and Sinks: 1990–2013’’, Report EPA 

430–R–15–004, United States Environmental 

Protection Agency, April 15 2015. http://www.epa.

gov/climatechange/ghgemissions/ 

usinventoryreport.html. 

27U.S. EPA Greenhouse Gas Reporting Program 

Dataset as of August 18, 2014. http:// 

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

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

of affected sources is based on the date that the EPA 

proposes action on such sources. January 8, 2014 

is the date the proposed GHG standards of 

performance for new fossil fuel-fired EGUs were 

published in the Federal Register (79 FR 1430). 

TABLE 3—U.S. GHG EMISSIONS AND SINKS BY SECTOR

[Million metric tons carbon dioxide equivalent (MMT CO2 Eq.)] 22

Sector 1990 2005 2013 

Energy 23 ...................................................................................................................................... 5,290.5 6,273.6 5,636.6 

Industrial Processes and Product Use ........................................................................................ 342.1 367.4 359.1 

Agriculture .................................................................................................................................... 448.7 494.5 515.7 

Land Use, Land-Use Change and Forestry ................................................................................ 13.8 25.5 23.3 

Waste ........................................................................................................................................... 206.0 189.2 138.3 

Total Emissions .................................................................................................................... 6,301.1 7,350.2 6,673.0 

Land Use, Land-Use Change and Forestry (Sinks) .................................................................... (775.8) (911.9) (881.7) 

Net Emissions (Sources and Sinks) ..................................................................................... 5,525.2 6,438.3 5,791.2 

Total fossil energy-related CO2

emissions (including both stationary 

and mobile sources) are the largest 

contributor to total U.S. GHG emissions, 

representing 77.3 percent of total 2013 

GHG emissions.24 In 2013, fossil fuel 

combustion by the utility power 

sector—entities that burn fossil fuel and 

whose primary business is the 

generation of electricity—accounted for 

38.3 percent of all energy-related CO2

emissions.25 Table 4 of this preamble 

presents total CO2 emissions from fossil 

fuel-fired EGUs, for years 1990, 2005, 

and 2013. 

TABLE 4—U.S. GHG EMISSIONS FROM GENERATION OF ELECTRICITY FROM COMBUSTION OF FOSSIL FUELS (MMT 

CO2) 26

GHG emissions 1990 2005 2013 

Total CO2 from fossil fuel-fired EGUs ......................................................................................... 1,820.8 2,400.9 2,039.8 

—from coal ........................................................................................................................... 1,547.6 1,983.8 1,575.0 

—from natural gas ................................................................................................................ 175.3 318.8 441.9 

—from petroleum .................................................................................................................. 97.5 97.9 22.4 

In addition to preparing the official 

U.S. GHG Inventory, which represents 

comprehensive total U.S. GHG 

emissions and complies with 

commitments under the UNFCCC, the 

EPA collects detailed GHG emissions 

data from the largest emitting facilities 

in the United States through its GHGRP. 

Data collected by the GHGRP from large 

stationary sources in the industrial 

sector show that the utility power sector 

emits far greater CO2 emissions than any 

other industrial sector. Table 5 of this 

preamble presents total GHG emissions 

in 2013 for the largest emitting 

industrial sectors as reported to the 

GHGRP. As shown in Table 4 and Table 

5 of this preamble, respectively, CO2

emissions from fossil fuel-fired EGUs 

are nearly three times as large as the 

total reported GHG emissions from the 

next ten largest emitting industrial 

sectors in the GHGRP database 

combined. 

TABLE 5—DIRECT GHG EMISSIONS

REPORTED TO GHGRP BY LARGEST

EMITTING INDUSTRIAL SECTORS

(MMT CO2e) 27

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 

C. Affected EGUs 

For the Clean Power Plan and this 

federal plan, an affected EGU is any 

SGU, IGCC, or stationary combustion 

turbine that was in operation or had 

commenced construction as of January 

8, 2014,28 and that meets the following 

criteria, which differ depending on the 

type of unit. To be an affected EGU, 

such a unit, if it is SGU or IGCC, must 

serve a generator capable of selling 

greater than 25 MW to a utility power 

distribution system and have a base load 

rating greater than 260 GJ/h (250 

MMBtu/h) heat input of fossil fuel 

(either alone or in combination with any 

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

unit must meet the definition of a 

combined cycle or CHP combustion 

turbine, serve a generator capable of 

selling greater than 25 MW to a utility 

power distribution system, and have a 

base load rating of greater than 260 GJ/ 

h (250 MMBtu/h). 

When considering and understanding 

applicability, the following definitions 

may be helpful. Simple cycle 

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64980 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Proposed Rules 

29We had proposed in the Clean Power Plan EGs 

that affected EGUs were those existing source fossil 

fuel-fired EGUs that met the applicability criteria 

for coverage under the final GHG standards for new 

fossil fuel-fired EGUs being promulgated under 

CAA section 111(b). However, we are finalizing in 

the EGs that states need not include certain units 

that would otherwise meet the CAA section 111(b) 

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

include simple cycle turbines, certain non-fossil 

units, and certain CHP units. The final CAA section 

111(b) standards include applicability criteria for 

simple cycle combustion turbines, for reasons 

relating to implementation and minimizing 

emissions from all future combustion turbines. 

30This schedule would be the same under either 

a rate- or mass-based approach. 

combustion turbine means any 

stationary combustion turbine which 

does not recover heat from the 

combustion turbine engine exhaust 

gases for purposes other than enhancing 

the performance of the stationary 

combustion turbine itself. Combined 

cycle combustion turbine means any 

SCT which recovers heat from the 

combustion turbine engine exhaust 

gases to generate steam that is used to 

create additional electric power output 

in a steam turbine. CHP combustion 

turbine means any SCT which recovers 

heat from the combustion turbine 

engine exhaust gases to heat water or 

another medium, generates steam for 

useful purposes other than exclusively 

for additional electric generation, or 

directly uses the heat in the exhaust 

gases for a useful purpose. 

We note that certain affected EGUs are 

exempt from inclusion in a state plan 

and this federal plan. Affected EGUs 

that may be excluded under the EGs are 

those that (1) Are subject to subpart 40 

CFR part 60, subpart TTTT as a result 

of commencing modification or 

reconstruction; (2) are SGUs or IGCC 

that are currently and always have been 

subject to a federally enforceable permit 

limiting net-electric sales to one-third or 

less of its potential electric output or 

219,000 MWh or less on an annual 

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

that are capable of combusting 50 

percent or more non-fossil fuel) that 

have historically limited the use of 

fossil fuels to 10 percent or less of the 

annual capacity factor or are subject to 

a federally enforceable permit limiting 

fossil fuel use to 10 percent or less of 

the annual capacity factor; (4) are 

stationary combustion turbines that are 

not capable of combusting natural gas 

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

pipeline); (5) are CHP units that are 

subject to a federally enforceable permit 

limiting, or have historically limited, 

annual net electric sales to a utility 

power distribution system to the 

product of the design efficiency and the 

potential electric output or 219,000 

MWh (whichever is greater) or less; (6) 

serve a generator along with other 

SGU(s), IGCC(s), or stationary 

combustion turbine(s) where the 

effective generation capacity 

(determined based on a prorated output 

of the base load rating of each SGU, 

IGCC, or stationary combustion turbine) 

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

waste combustor unit subject to subpart 

Eb of 40 CFR part 60; or (8) are a 

commercial or industrial solid waste 

incineration unit that is subject to 

subpart CCCC of 40 CFR part 60.29

The EPA also requests comment on an 

alternative compliance pathway that 

could be available to units under a 

mass-based approach. The ways that the 

approach could be implemented are 

further outlined in the Alternative 

Compliance Pathway for Units that 

Agree to Retire Before a Certain Date 

Technical Support Document (TSD). 

Under this approach, two basic 

requirements would need to be met. The 

first is that the unit would have to take 

a commitment that it would retire on a 

date on or before December 31, 2029. 

The second is that the unit would have 

to demonstrate that it will take an 

enforceable emission limitation that 

would assure that the overall state 

emission goal is met. The TSD explores 

ways that this approach could be 

implemented, including ways that the 

enforceable emission limitation could 

be calculated and implemented. The 

EPA requests comment on whether this 

approach should be available for all 

units or limited to small units (e.g. less 

than 100 MW nameplate capacity). The 

EPA also requests comment on whether 

and how such an approach could be 

included under a rate-based approach. 

The applicability of this proposed 

federal plan follows the same 

applicability criteria as the final EGs. 

The rationale for these criteria is 

provided in section IV.D of the Clean 

Power Plan. We are not reopening the 

criteria or rationale here. 

In the federal plan Affected EGU TSD, 

the EPA lists all applicable affected 

EGUs according to our records from the 

National Electric Energy Data System 

(NEEDS), Energy Information 

Administration (EIA), and comments 

from the Clean Power Plan. In this TSD, 

each affected EGU is assigned its 

proposed applicable standards if a 

federal plan were to be promulgated for 

that affected EGU at any time. The EPA 

requests comments and updates to this 

list of affected units. Section VI.C of the 

final EGs describes the data used in 

setting the standards and how an 

inventory of affected units has been 

compiled. 

D. Compliance Schedule 

In accordance with the schedule set 

out in the EGs, the federal plan is 

proposed to be implemented in a 

phased approach. The first period, 

corresponding to the Interim Period in 

the EG, is proposed to run from 

beginning of calendar year 2022 until 

end of calendar year 2029 (January 1, 

2022 to December 31, 2029). The Final 

Period would run from beginning of 

calendar year 2030 (January 1, 2030) 

indefinitely into the future. The first 

period is proposed to be comprised of 

three ‘‘compliance periods,’’ set by 

calendar year. The first compliance 

period will be from January 1, 2022 to 

midnight, December 31, 2024 (3 

calendar years). The second compliance 

period will be from January 1, 2025 to 

midnight, December 31, 2027 (3 

calendar years). The third compliance 

period will be from January 1, 2028 to 

midnight, December 31, 2029 (2 

calendar years). 

Under the EGs, midnight, December 

31, 2029 marks the end of the Interim 

Period, and the beginning of the Final 

Period. The EPA proposes that the 

compliance periods in the Final Period 

will each be 2 calendar years. Thus, the 

first compliance period after 2030 

would be from January 1, 2030 to 

midnight, December 31, 2031. The 

second compliance period would be 

from January 1, 2032 to midnight, 

December 31, 2033. This would repeat 

accordingly unless changed by the EPA 

through a revision to the federal plan or 

other action.30

The EPA recognizes that the 

compliance periods provided for in this 

rulemaking are longer than those 

historically and typically specified in 

CAA rulemakings. As reflected in longstanding CAA precedent, ‘‘[t]he time 

over which [the compliance standards] 

extend should be as short term as 

possible and should generally not 

exceed one month.’’ See e.g., June 13, 

1989 Guidance on Limiting Potential to 

Emit in New Source Permitting and 

January 25, 1995 Guidance on 

Enforceability Requirements for 

Limiting Potential to Emit through SIP 

and § 112 Rules and General Permits. 

The EPA determined that the longer 

compliance periods provided for in this 

rulemaking are acceptable in the context 

of this specific rulemaking because of 

the unique characteristics of this 

rulemaking, including that CO2 is longlived in the atmosphere, and this 

rulemaking is focused on performance 

standards related to those long-term 

impacts. 

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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Proposed Rules 64981 

31The EPA evaluated certain aspects of electric 

reliability in the context of modeling projections for 

the final Clean Power Plan, and that evaluation is 

described in the ‘‘Resource Adequacy and 

Reliability Analysis TSD’’ for that rulemaking, a 

copy of which is also included in the docket for this 

rulemaking. 

32Casazza, 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. 

34NERC Reliability Standard EOP–001–2.1b— 

Emergency Operations Planning, available at http:// 

www.nerc.net/standardsreports/

standardssummary.aspx. 

Prior to the beginning of the first 

compliance period in 2022, the agency 

intends to establish the infrastructure 

for operating a federal trading program 

and to work closely with affected EGUs 

in the states where the federal plan is 

promulgated prior to the start of the first 

compliance period in 2022. We request 

comment on whether it would be 

possible to grant, on a case-by-case 

basis, certain affected EGUs, particularly 

small entities, additional time to come 

into compliance, and to request 

additional input from the public as to 

the design of such flexibility that would 

be compatible with the EGs and a 

federal plan that implements a trading 

system. 

The EPA recognizes that it is 

important to ensure a degree of liquidity 

in compliance instruments in either of 

the proposed trading approaches, while 

also maintaining the stringency required 

by the final EGs. A number of aspects 

of the rate-based and mass-based 

programs would assist with this, 

including allocation methods or rules, 

mechanisms to place allowances or 

credits into the market relatively early, 

requirements for public transparency of 

information related to allowance, or 

credit issuance, tracking, transfers and 

holdings. The EPA solicits comment on 

other approaches to ensure market 

liquidity while continuing to meet the 

stringency of the final EGs. 

E. Addressing Reliability Concerns 

The proposed federal plan has been 

designed to ensure that, to the greatest 

extent possible, implementation would 

not interfere with the power sector’s 

ability to maintain electric reliability.31

Like the EGs, the federal plan provides 

a long planning horizon and 

implementation period. In addition the 

federal plan allows affected EGUs to 

obtain tradable allowances and credits 

to meet obligations which assures that 

reliability can be maintained without 

disruption to the electricity system. 

There are many features of the 

electricity system that ensure that 

electric system reliability will be 

maintained. For example, in the Energy 

Policy Act of 2005, Congress added a 

section to the Federal Power Act to 

make reliability standards mandatory 

and enforceable by the Federal Energy 

Regulatory Commission (FERC) and the 

North American Electric Reliability 

Corporation (NERC), the Electric 

Reliability Organization which FERC 

designated and oversees. Along with its 

standards development work, NERC 

conducts annual reliability assessments 

via a 10-year forecast and winter and 

summer forecasts; audits owners, 

operators and users for preparedness; 

and educates and trains industry 

personnel. Numerous other entities such 

as FERC, U.S. Department of Energy 

(DOE), state public utility commissions 

(PUCs), independent system operators 

and regional transmission organizations 

(ISOs/RTOs), and other planning 

authorities also consider the reliability 

of the electric system. There are also 

numerous remedies that are routinely 

employed when there is a specific local 

or regional reliability issue. These 

include transmission system upgrades, 

installation of new generating capacity, 

calling on demand response, and other 

demand-side actions. 

Additionally, planning authorities 

and system operators constantly 

consider, plan for and monitor the 

reliability of the electricity system with 

both a long-term and short-term 

perspective. Over the last century, the 

electric industry’s efforts regarding 

electric system reliability have become 

multidimensional, comprehensive and 

sophisticated. Under this 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 Longterm system planning happens at both 

the local and regional levels with all 

segments of the electric system needing 

to operate together in an efficient and 

reliable manner. In the short-term, 

electric system operators operate the 

system within safe operating margins 

and work to restore the system quickly 

if a disruption occurs.33 Mandatory 

reliability standards apply to how the 

bulk electric system is planned and 

operated. For example, transmission 

operators and balancing authorities have 

to develop, maintain and implement a 

set of plans to mitigate operating 

emergencies.34

The EPA’s approach in this proposed 

federal plan builds on the foundation 

provided in the EGs’ determination of 

the BSER to ensure that the final federal 

plan, like the final EGs, does not 

interfere with the industry’s ability to 

maintain reliability of the nation’s 

electricity supply. First, the federal 

plan, like the EGs, provides more than 

6 years before reductions are required 

and an 8-year period from 2022 to 2029 

to meet interim goals. This allows time 

for planning and steady, measured 

implementation. 

Second, the federal plan is a marketbased trading program which will allow 

affected EGUs the opportunity to buy 

and sell emissions credits or allowances 

as well as bank them. The EPA’s 

proposed federal plan includes two 

alternative approaches: A mass-based 

trading program and a rate-based trading 

program. Trading programs of both 

types have many positive attributes. 

Among them is that they help to ensure 

that imposition of the federal plan will 

not interfere with the industry’s ability 

to maintain the reliability of the nation’s 

electricity supply. Such a program does 

not restrict unit-level operational 

decision-making beyond requiring units 

to hold a sufficient number of tradable 

permits (e.g., allowances or ERCs) to 

cover emissions. It, therefore, inherently 

allows for unit-level operational 

flexibility to facilitate the maintenance 

of reliability and makes the program 

enormously resilient. If a unit finds it 

needs to run more than anticipated, the 

market-based 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 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 

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64982 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Proposed Rules 

35We note that the preamble and supporting 

materials for the EGs discuss a related concern 

raised by some stakeholders, which is whether the 

EGs could result in widespread ‘‘stranded assets’’ 

as a direct result of the rule. As explained there, we 

believe this concern is distinct from the ‘‘remaining 

useful lives’’ factor in CAA section 111(d)(1), and 

for the same reasons, believe it is distinct from the 

factor Congress directed the agency to consider in 

CAA section 111(d)(2). Nonetheless, we undertook 

analysis in the final EGs of whether and to what 

extent there may be a ‘‘stranded asset’’ concern. See 

memorandum to Clean Power Plan Docket EPA– 

HQ–OAR–2013–0602 titled ‘‘Stranded Assets 

Analysis’’ dated July 2015. We believe that analysis 

demonstrates that this is not likely to be a 

widespread issue under the federal plan either. 

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 EGs and the 

final federal plan in any state that does 

not have an approved state plan. The 

three agencies have developed a 

coordination strategy that reflects their 

joint understanding of how they will 

work together to monitor 

implementation. The three agencies will 

work together to monitor 

implementation, share information and 

resolve any difficulties that may be 

encountered. 

The EPA is not proposing to include 

an allowance set-aside, or similar 

mechanism in a rate-based approach, to 

address reliability issues in the federal 

plan; however, we request comment on 

including such a set-aside in the context 

of a 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 

allowances 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 of this 

preamble. The EPA requests comment 

on all elements of such an approach, 

including what events would trigger the 

need for allowances from the reliability 

set-aside; eligibility criteria to receive 

the set-aside allowances; the size of the 

set-aside; and the timing of distribution 

of allowances from the reliability setaside. Additionally, the EPA requests 

comment on how a reliability ‘‘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 CEIP, which was 

established in the EGs to reward 

investment in certain clean energy 

projects that achieve MWh results 

during 2020 and 2021 (see sections IV 

and V of this preamble for the proposed 

approach to implement this incentive 

program in the rate-based and massbased federal plans, respectively). 

Implementation of the CEIP in the 

federal plans would create ERCs and 

allowances before 2022, allowing for 

creation of banks that could be used in 

the event of an unforeseen, emergency 

reliability issue. The EPA requests 

comment on the potential for these 

banks of ERCs and allowances to 

support reliable electricity generation 

and transmission to be utilized in the 

event of this kind of reliability 

emergency. 

F. Worker Certification 

In the EGs, the EPA suggested that to 

ensure that emission reductions are 

realized, it is important that 

construction, operations and other 

skilled work undertaken pursuant to 

state plans is performed to 

specifications, and is effective, safe, and 

timely. The EPA asks for comments as 

to whether the federal plan should 

encourage EGUs to ask for a 

demonstration that the work undertaken 

under a federal plan is performed by a 

proficient workforce. A good way to 

ensure such a workforce is to require 

that workers have been certified by: (1) 

An apprenticeship program that is 

registered with the U.S. Department of 

Labor (DOL), Office of Apprenticeship 

or a state apprenticeship program 

approved by the DOL; (2) a skill 

certification aligned with the DOE 

Better Building Workforce Guidelines 

and validated by a third party 

accrediting body recognized by DOE; or 

(3) other skill certification validated by 

a third party accrediting body. 

G. Remaining Useful Lives and Potential 

for ‘‘Stranded Assets’’ 

Section 111(d)(2) of the CAA 

provides, ‘‘In promulgating a standard 

of performance under a plan prescribed 

under this paragraph, the Administrator 

shall take into consideration, among 

other factors, remaining useful lives of 

the sources in the category of sources to 

which such standard applies.’’ 42 U.S.C. 

7411(d)(2). This language tracks similar 

language in CAA section 111(d)(1) with 

respect to state plans. In the final EGs, 

we explained how the Guidelines 

permit states in applying a standard of 

performance in their state plans to 

consider the remaining useful life of a 

facility. We determined that it was 

appropriate to specify that the general 

variance provisions in 40 CFR 60.24(f) 

should not apply to the class of affected 

facilities covered by these Guidelines. 

We concluded that facility-specific 

factors and in particular, remaining 

useful life, do not justify a state making 

further adjustments to the performance 

rates or aggregate emission goal that the 

Guidelines define for affected EGUs in 

a state and that must be achieved by the 

state plan. 

Because the Guidelines do not allow 

for states to deviate from state goals 

based on remaining useful life, the EPA 

does not believe such goal adjustments 

are necessary or appropriate in the 

federal plan either. Nonetheless, this 

does not obviate the requirement that 

the EPA itself, in the design of its 

federal plan, consider, among other 

factors, the remaining useful lives of the 

affected facilities. The agency therefore 

proposes the following analysis of this 

factor.35

Congress added the ‘‘remaining useful 

lives’’ factor to CAA section 111(d)(2) in 

the 1977 CAA Amendments. Congress 

did not provide in the statute any 

direction on how or to what degree 

‘‘remaining useful lives’’ of facilities 

subject to a section 111(d) federal plan 

is to be considered. As discussed in the 

preamble to the final EGs, Congress’ 

intent in enacting the provision was to 

allow for older facilties with short 

remaining useful lives to not be required 

to install capital-intensive pollution 

control devices to meet emission 

standards that would only be used for 

a short period of time before a plant 

ceased operation. A House of 

Representatives report on a predecessor 

bill to the enacted statute stated, ‘‘Older 

plants with relatively short remaining 

useful lives might have chosen to cease 

operation if the only means of emission 

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36Because we believe that this is the case for all 

facilities through the basic design of the federal 

plan, we also can confirm, in line with the EGs, that 

the availability of variances from the emission 

standards is unnecessary in the federal plan. Under 

the general framework regulations, facility-specific 

variances from an otherwise applicable standard of 

performance have been potentially available under 

the application process in 40 CFR 60.27(e)(2), 

which incorporates the factors provided in 40 CFR 

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

federal plan adequately considers remaining useful 

lives, and for the same reasons, the need for facilityspecific variances under the circumstances of 

60.24(f) (unreasonable costs of controls, physical 

impossibility of installation of necessary control 

equipment, or other factors that make longer 

compliance times or less stringent standards 

significantly more reasonable) is not expected to 

arise, and thus, the agency proposes to make 40 

CFR 60.27(e) inapplicable in this federal plan. 

limitation available to meet emission 

limits were pollution control 

technology.’’ H. Report 94–1175, at 159 

(1976) (emphasis added). This language 

is probative of the fact that Congress 

viewed ‘‘remaining useful lives’’ as a 

consideration for facilities with 

relatively little remaining useful life. We 

are confident the proposed federal plan 

will not force costly pollution control 

investments at older plants with short 

remaining useful lives. 

Further, the statute provides that this 

factor is one ‘‘among other factors’’ that 

the agency is to consider in 

promulgating a standard of 

performance. Congress provided no 

guidance in the statute as to what those 

other factors could be. The inclusion of 

unspecified factors that the agency may 

determine for itself to consider, along 

with the use of the term ‘‘consider,’’ 

highlights that Congress intended to 

give the agency a substantial degree of 

discretion in determining how the 

‘‘remaining useful lives’’ factor is 

considered. The statute does not 

require, and Congress did not intend, 

that this consideration mandate the 

agency to prevent all premature 

retirements of affected EGUs, to impose 

no emission requirements on older 

affected EGUs, or to ensure that 

profitability is maintained at all times 

for all affected EGUs. Congress knew 

how to explicitly exempt older plants 

from CAA requirements at the time of 

the 1977 Amendments. For example, 

Congress excluded plants in existence 

before August 7, 1977 from the 

preconstruction requirements of the 

prevention of significant deterioration 

(PSD)/non-attainment new source 

review (NSR) program, see CAA section 

165(a). And in CAA section 169A 

related to visibility impairment in 

federal class I areas, Congress excluded 

from applicability units that began 

operation before August 7, 1962. 42 

U.S.C. 7491(b)(2)(A). In CAA section 

111(d) Congress did not set any such 

specific criteria. Rather it directed the 

agency to ‘‘consider’’ the remaining 

useful lives of facilities, among other 

factors. 

This view also accords with past 

agency practice in implementing a 

similar provision. In the 1977 

Amendments, Congress listed 

‘‘remaining useful life’’ as a factor for 

consideration in the visibility program 

under section 169A. 42 U.S.C. 7491. The 

‘‘remaining useful life of the source’’ is 

one of several enumerated factors that 

the state or the EPA is to consider in 

determining the best available retrofit 

technology (BART) for a particular 

source. Consistent with congressional 

purpose, the EPA has implemented this 

factor in the regional haze program for 

many years through the BART 

guidelines, in appendix Y to 40 CFR 

part 51. In the context of the visibility 

program, we have interpreted this 

provision to mean that the remaining 

useful life should be considered when 

calculating the annualized costs of 

retrofit controls. See 40 CFR part 51, 

appendix Y, section IV.D.4.k. In the 

agency’s view, this approach to 

‘‘remaining useful life’’ aligns with 

congressional intent and informs our 

view of how the ‘‘remaining useful 

lives’’ factor should be considered 

under this CAA section 111(d) federal 

plan. The key consideration is whether 

the time period associated with 

amortizable costs of compliance will 

exceed the remaining useful lives of the 

sources in question. 

Consistent with legislative intent and 

past agency practice, we propose that 

the federal plan adequately considers 

‘‘remaining useful lives’’ of affected 

EGUs by providing for trading and other 

flexibilities authorized in the EGs. To 

summarize, these include: Relatively 

long periods for affected EGUs to come 

into compliance, the ability to credit 

early action, the use of emissions 

trading, the use of multi-year 

compliance periods, and the ability to 

link to other federal or state plans to 

create larger emissions markets. The 

federal plan is proposed to include a 

Clean Energy Incentive Program as 

provided for in the EGs, which will 

credit early action and ease compliance 

in the initial years of the program. These 

tools will create economic incentives 

that reward over-performance of some 

affected EGUs, and allow others to 

simply acquire credits or allowances to 

comply with their emission standard, 

thereby avoiding the need for 

installation of costly pollution controls 

at sources with a short remaining life. 

Thus, the proposed federal plan is 

designed in such a way that it 

adequately, and inherently, takes into 

account the remaining useful lives of 

affected EGUs. It provides substantial 

compliance flexibility, including means 

of avoiding the need to make extensive 

capital investments in control 

technologies that could not be recouped 

during the remaining useful lives of a 

facility.36 The design of the federal plan 

as a form of emission trading provides 

individual affected EGUs the flexibility 

to make cost-conscious compliance 

choices. This flexibility avoids or 

substantially diminishes any likelihood 

that compliance will be a physical 

impossibility or result in unreasonable 

costs. 

By relying on either rate- or massbased emission trading, the proposed 

federal plan capitalizes on the inherent 

flexibility available through marketbased techniques. In effect, under a 

trading program with repeating 

compliance periods, a facility with a 

short remaining useful life has a total 

outlay that is proportionately smaller 

than a facility with a long remaining 

useful life, simply because the first 

facility would need to comply for fewer 

compliance periods and would need 

proportionately fewer ERCs or 

allowances than the second facility. 

Buying ERCs or allowances as a 

compliance method could avoid 

excessive up-front capital expenditures 

that might be unreasonable for facilities 

with short remaining useful lives, and 

therefore addresses the consideration of 

‘‘remaining useful lives.’’ Buying ERCs 

or allowances as a compliance method 

also would reduce the potential for 

stranded assets. 

In addition, the timing of the federal 

plan limits the immediate costs of 

compliance, particularly for facilities 

that have useful lives ending before 

2022, but also for facilities that have 

useful lives ending before 2030. There 

are no compliance obligations for 

affected EGUs under this federal plan 

until 2022, when the first compliance 

period begins. At that point, the agency 

is following the glide path provided for 

in the EGs, which begins with relatively 

higher emission targets that will slowly 

strengthen over the interim performance 

period from 2022–2029 through three 

multi-year compliance periods. The 

final, most stringent, compliance 

obligation does not begin until 2030. 

Further, unlike state plans that can be 

more stringent under CAA section 116, 

the federal plan is no more stringent 

than the EGs, and, as explained in the 

EGs, the Guidelines reflect a reasonable, 

rather than a maximum possible, 

implementation level for each building 

block in order to establish overall goals 

that are achievable. As discussed in the 

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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. 

38Part 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. 

39Memorandum 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). 

EGs, the BSER determined an average 

level of emissions achievable by groups 

of EGUs, rather than for an individual 

EGU. In considering the remaining 

useful lives of facilities under a federal 

plan, the EPA believes this approach to 

setting the emission standards, coupled 

with the ability to trade, adequately 

accounts for remaining useful lives of 

facilities. In essence, it allows the 

facilities to comply with the federal 

plan through the purchase or 

acquisition of ERCs or allowances, and 

to avoid the need to make costly 

investments in control technology for 

plants that have short remaining useful 

lives.37 For these reasons, the federal 

plan adequately considers ‘‘remaining 

useful lives.’’ We invite comment on our 

consideration of facilities’ ‘‘remaining 

useful lives’’ in the federal plan. 

H. Implications for Other EPA Programs 

and Rules 

1. Title V Permitting 

Under the proposed federal plan, title 

V permits for sources with affected 

EGUs will need to include any new 

applicable requirements that the plan 

places on the affected EGUs. The EPA, 

however, is not proposing any 

permitting requirements independent of 

those that would be required under title 

V of the CAA and the regulations 

implementing title V, 40 CFR parts 70 

and 71.38 All major stationary sources of 

air pollution and certain other sources 

are required to apply for title V 

operating permits that include emission 

limitations and other conditions as 

necessary to assure compliance with 

applicable requirements of the CAA, 

including the requirements of an 

applicable CAA section 111(d) state 

plan or federal plan. CAA sections 

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

and 7661c(a). The ‘‘applicable 

requirements’’ that must be addressed in 

title V permits are defined in the title V 

regulations, and include requirements 

under CAA section 111(d) (40 CFR 70.2 

and 71.2 (definition of ‘‘applicable 

requirement’’)). 

The EPA anticipates that, given the 

nature of the units covered by the 

proposed federal plan, most of the 

sources at which they are located are 

already or will be subject to title V 

permitting requirements. For sources 

subject to title V, the requirements 

applicable to them under the proposed 

federal plan will be ‘‘applicable 

requirements’’ under title V and, 

therefore, will need to be addressed in 

the title V permits. For example, 

requirements under the proposed 

federal plan concerning designated 

representatives, monitoring, reporting, 

and recordkeeping, the requirement to 

either meet an emission rate (including 

through holding ERCs (rate-based 

approach)), or to hold allowances 

covering emissions (mass-based 

approach) will be ‘‘applicable 

requirements’’ to be addressed in the 

permits. 

The EPA does not believe this 

approach is affected by the Supreme 

Court’s decision in Utility Air 

Regulatory Group v. U.S. EPA, 134 S. Ct. 

2427 (June 23, 2014). The Supreme 

Court held that the EPA may not treat 

GHGs as an air pollutant for purposes of 

determining whether a source is a major 

source required to obtain a title V 

operating permit. In accordance with 

that decision, the D.C. Circuit’s 

amended judgment on April 10, 2015 

vacated the title V regulations under 

review in that case (40 CFR 70.12 and 

71.13) to the extent that they require a 

stationary source to obtain a title V 

permit solely because the source emits 

or has the potential to emit GHGs above 

the applicable major source thresholds. 

The D.C. Circuit also directed the EPA 

to consider whether any further 

revisions to its regulations are 

appropriate in light of UARG v. EPA, 

and, if so, to undertake to make such 

revisions. As the agency made clear in 

a memorandum to Regional 

Administrators last year, ‘‘While the 

EPA will no longer apply or enforce the 

requirement that a source obtain a title 

V permit solely because it emits or has 

the potential to emit GHGs above major 

source thresholds, the agency does not 

read the Supreme Court decision to 

affect other grounds on which a title V 

permit may be required or the 

applicable requirements that must be 

addressed in title V permits.’’ 39

Accordingly, while the emission of 

GHGs alone cannot trigger the need for 

a title V permit under UARG, the EPA 

believes a final federal plan under CAA 

section 111(d) will create new 

‘‘applicable requirements’’ in the form 

of an emission standard (either an 

emission rate or an allowance system) 

and related requirements for GHGs 

(here, CO2) on affected EGUs. See 40 

CFR 70.2, 71.2 (definition of ‘‘applicable 

requirement’’ includes ‘‘any standard or 

other requirement under section 111 of 

the Act, including section 111(d)’’) 

(emphasis added). Thus, an affected 

EGU may be required to modify its 

existing title V permit, or obtain a new 

permit if it does not already have one, 

if it becomes subject to an emission 

standard for CO2 under a CAA section 

111(d) federal plan. 

The title V permits program is 

structured to provide flexibility for 

market-based approaches, such as 

allowance trading programs under the 

federal plan, including flexibility to 

make changes under such programs 

without necessarily requiring a formal 

permit revision. For example, the title V 

regulations provide that a permit issued 

under title V shall include, for any 

‘‘approved * * * emissions trading or 

other similar programs or processes’’ 

applicable to the source, a provision 

stating that no permit revision is 

required ‘‘for changes that are provided 

for in the permit.’’ 40 CFR 70.6(a)(8) and 

71.6(a)(8). Consistent with this 

provision in the title V regulations, the 

proposed federal plan regulations 

include a provision stating that no 

permit revision shall be required for the 

allocation, holding, deduction, or 

transfer of allowances once the 

requirements applicable to such 

allocations, holdings, deductions, or 

transfers of CO2 allowances are already 

incorporated in such permit. Consistent 

with title V regulations, this provision 

should be included in each title V 

permit for a covered source. As a result, 

allowances will be able to be traded (or 

allocated, held, or deducted) under the 

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, and consistent with 40 

CFR 70.7(e)(2)(i)(B) and 40 CFR 

71.7(e)(1)(i)(B), the EPA is proposing 

that any changes that may be required 

to an operating permit with respect to a 

trading program under the federal plan 

may be made using the minor permit 

modification procedures of the title V 

rules. The EPA proposes that such 

changes may include the initial changes 

needed to the title V permit to establish 

the applicability of the trading program 

to the source, specify the covered units, 

and to include other permit terms that 

may be needed for implementation, 

including the general approach for 

monitoring and reporting. The minor 

permit modification procedures could 

also be used for any subsequent changes 

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40Memorandum from Anna Marie Wood, 

Director, Air Quality Policy Division, Office of Air 

Quality Planning and Standards (OAQPS), and Reid 

P. Harvey, Director, Clean Air Markets Division, 

Office of Atmospheric Programs (OAP), to Regional 

Air Division Directors, 1–7, regarding Title V Permit 

Guidance and Template for the Cross-State Air 

Pollution Rule (May 13, 2015). 

41We 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. 

42The Supreme Court recently reversed and 

remanded a DC 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. 

to permit terms that may be needed with 

respect to the trading program, although 

we expect such changes to be 

infrequent. As noted above, once a 

trading program has been established in 

the permit, there may be transactions, 

such as individual trades, that will 

require no formal permit modification 

procedures because such trading would 

be already addressed and allowed by the 

permit (‘‘provided for in the permit’’) 

provided the changes do not conflict 

with any existing terms of the permit. If 

a source wishes to make a change that 

would go against any express term of 

the permit, the permit must be revised 

to allow such a change before the source 

begins operation of the change. Under 

the implementation strategy described 

above, the EPA believes it would be 

unlikely that any change in trading 

allowances would violate a term of a 

permit, but this principle is important to 

keep in mind when deciding if a minor 

permit modification is appropriate with 

respect to operating a trading program 

in the context of a title V permit. 

The EPA believes that the approach to 

permitting requirements we are 

proposing here, which imposes no 

additional permitting requirements 

independent of title V and provides for 

the use of minor permit modification 

procedures, will streamline the process 

for sources already required to be 

permitted under title V and for 

permitting authorities. If there are any 

sources that would become newly 

subject to title V as a result of the 

requirements of this proposed federal 

plan, the initial title V permit that 

would be issued pursuant to 40 CFR 

70.7(a) or 71.7(a) would address the 

federal plan requirements, when 

finalized. 

The EPA notes that the approach to 

title V permitting that is being proposed 

is somewhat similar to the approach 

adopted in the final CSAPR. See 76 FR 

48299–48300 (August 8, 2011). The 

agency recently issued guidance to 

assist permitting authorities and sources 

subject to CSAPR in incorporating 

CSAPR requirements into title V 

permits.40 The EPA invites comment on 

its proposed approach to permitting 

requirements for the federal plan, 

including whether it would be of use to 

develop guidance similar to the 

guidance developed for permitting 

under CSAPR. The EPA invites 

comment on its proposed approach to 

incorporating applicable requirements 

of the federal plan into title V permits 

and revising those requirements, 

including specifically seeking comment 

on whether all requirements should be 

eligible for incorporation into title V 

permits via minor modification 

procedures or if only a specified subset 

of such requirements should be eligible 

for such procedures. 

The EPA also notes that the 

applicable requirements of this 

proposed federal plan would apply to a 

source and are independently 

enforceable regardless of whether they 

have yet been included in the source’s 

Title V permit. 

2. Implications for New Source Review 

Program 

The NSR program is a preconstruction 

permitting program that requires major 

stationary sources of air pollution to 

obtain permits prior to beginning 

construction. The requirements of the 

NSR program apply both to new 

construction and to modifications of 

existing major sources. Generally, a 

source triggers these permitting 

requirements as a result of a 

modification when it undertakes a 

physical or operational change that 

results in a significant emission increase 

and a net emissions increase. NSR 

regulations define what constitutes a 

significant net emissions increase, and 

the concept is pollutant-specific. 

In the final EGs, the EPA recognized 

that, as part of its CAA section 111(d) 

plan, a state may impose requirements 

that require an affected EGU to 

undertake a physical or operational 

change to improve the unit’s efficiency 

that results in an increase in the unit’s 

dispatch and an increase in the unit’s 

annual emissions. If the emissions 

increase associated with the unit’s 

changes exceeds the thresholds in the 

NSR regulations for one or more 

regulated NSR pollutants, including the 

netting analysis, the changes would 

trigger NSR. We noted that while there 

may be instances in which an NSR 

permit would be required, we expect 

those situations to be few. 

The EPA believes the analysis of NSR 

applicability is basically the same for 

sources under a CAA section 111(d) 

federal plan. That is, it is conceivable 

that a source under a federal plan may 

choose, as a means of compliance with 

either a rate-based or mass-based 

approach, to undertake a physical or 

operational change to improve an 

affected EGU’s efficiency that results in 

a significant net emissions increase of a 

regulated NSR pollutant. This would 

trigger NSR. However, as with state 

plans, the EPA believes that these 

situations will be few. 

After the proposal for the Clean Power 

Plan was published in June of 2014, the 

U.S. Supreme Court issued its opinion 

in UARG v. EPA, 134 S. Ct. 2427 (June 

23, 2014). The Supreme Court held that 

an increase in GHG emissions alone 

cannot by law trigger the NSR 

requirements of the PSD program under 

section 165 of the CAA. On remand 

from the Court, the DC Circuit issued an 

amended judgment in Coalition for 

Responsible Regulation, Inc. v. 

Environmental Protection Agency, Nos. 

09–1322, 10–073, 10–1092 and 10–1167 

(D.C. Cir., April 10, 2015), vacating the 

relevant regulations. Therefore, 

increases in emissions of GHGs alone, 

including those that may occur through 

actions taken at sources to comply with 

the proposed federal plan (such as may 

occur when an NGCC unit increases its 

operations due to generation shift from 

a SGU), cannot trigger NSR. 

The EPA will invite comment on 

potential scenarios in which affected 

EGUs, particularly small entities, could 

be subject to the requirements of the 

NSR program as a result of taking 

compliance measures under the federal 

plan, and any ideas for harmonizing or 

streamlining the permitting process for 

such sources that are consistent with 

judicial precedent. However, the EPA is 

not proposing any changes to the NSR 

program in this action, and the agency 

is not reopening or reconsidering any 

prior actions or determinations related 

to NSR in this action. Any comments 

related solely to the NSR program will 

be considered outside the scope of this 

proposed rule. 

3. Interactions With Other EPA Rules 

Existing fossil fuel-fired EGUs, such 

as those covered in this proposal, are or 

will be potentially impacted by several 

other rules recently finalized or 

proposed by the EPA.41 These rules 

include the Mercury and Air Toxics 

Standards (MATS) (77 FR 9304; 

February 16, 2012); 42 the CSAPR; 

Requirements for Cooling Water Intake 

Structures at Power Plants (79 FR 

48300; August 15, 2014); Disposal of 

Coal Combustion Residuals from 

Electric Utilities, promulgated on April 

17, 2015 (80 FR 21302); and the 

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43Section 111(d)(2) further provides that ‘‘[i]n 

promulgating a standard of performance under a 

plan prescribed under this paragraph, the 

Administrator shall take into consideration, among 

other factors, the remaining useful lives of the 

sources in the category of sources to which such 

standard applies.’’ The agency’s interpretation of 

the ‘‘remaining useful lives’’ provision is discussed 

above in section III.G of this preamble. 

proposed Steam Electric Effluent 

Limitation Guidelines and Standards 

(78 FR 34432; June 7, 2013). These rules 

are discussed in more detail in the final 

EGs along with steps the EPA is taking 

to enable compliance with obligations 

under other power sector rules as 

efficiently as possible. We solicit 

comment on whether there are specific 

things the EPA can do in the design and 

implementation of the federal plan that 

further this objective. 

I. Administrative Appeals Process 

Under either a rate-based or massbased trading program, the EPA 

anticipates that there may be situations 

in which individual parties are affected 

by decisions of the agency. For example, 

under a rate-based plan, a determination 

may be made that an eligibility 

application by an ERC provider is 

denied. And, for set-asides in the massbased program, an affected EGU may 

believe that its allowance allocation 

amount was miscalculated. Similar to 

prior trading programs, the agency 

believes it would be efficient and 

potentially avoid the need for recourse 

to litigation to provide an administrative 

appeals process. Therefore we are 

proposing, and requesting comment on, 

the use of the regulations for appeals 

procedures set forth in 40 CFR part 78, 

to provide for the adjudication of certain 

disputes that may arise during the 

course of implementation of a federal 

plan under CAA section 111(d). We also 

propose to revise part 78 to 

accommodate such appeals. The part 78 

procedures cover prior CAA emission 

trading programs and were specifically 

designed with these types of disputes in 

mind. 

The persons eligible to file such 

appeals would be designated 

representatives as defined in this 

proposed rule and other ‘‘interested 

persons’’ as defined in part 78. The 

filing of an appeal and the exhaustion 

of administrative remedies under part 

78 would be a prerequisite to seeking 

judicial review. For purposes of judicial 

review, final agency action would occur 

only when an agency decision under the 

federal plan listed as appealable under 

part 78 has been issued, and the 

procedures of part 78 for appealing the 

decision are exhausted. 

The actions we propose to list as 

appealable under the part 78 procedures 

are as follows: 

In the case of the rate-based federal 

plan: Decisions on an eligibility 

application for ERCs; decisions 

regarding the number of ERCs 

generated; decisions on the transfer of 

ERCs; decisions on the disallowance of 

ERCs for compliance; decisions that 

there has been an excess of emissions 

requiring a 2-for-1 ERC administrative 

compliance penalty; decisions regarding 

deduction or surrender of ERCs for 

compliance from affected EGUs’ 

compliance accounts; decisions on the 

accreditation of independent verifiers; 

the use of error corrections regarding 

information submitted by ERC 

providers, affected EGUs, or other ERC 

account holders; and the finalization of 

compliance period emissions data, 

including retroactive adjustment based 

on audit or other investigation. 

In the case of a mass-based federal 

plan: Decisions on an eligibilty 

application for set-aside allowances; 

decisions regarding the allocation of 

allowances to affected EGUs; decisions 

regarding the allocation of allowances 

from set-asides; decisions on the 

transfer of allowances; decisions 

regarding the finalization of emissions 

data by affected EGUs during 

compliance periods; decisions making 

error corrections to information 

submitted by affected EGUs and other 

account holders; decisions that there 

has been excess emissions requiring a 2- 

for-1 allowance administrative 

compliance penalty; and decisions 

regarding the deduction or surrender of 

allowances for compliance from affected 

EGUs’ compliance accounts. 

We request comment on this list of 

actions for both types of approaches to 

the federal plan, and whether there are 

other decisions that may be made in the 

course of implementation of the federal 

plan that are party-specific that would 

be appropriate to list as appealable 

under part 78. We also request comment 

on whether it would be appropriate for 

the EPA to finalize an administrative 

appeals process that differs in any way 

from that offered under part 78, or in 

addition to that offered under part 78. 

If so, we request comment broadly on all 

aspects of the alternative or additional 

adminsitrative appeals process, 

including with respect to any structural, 

procedural, subtantive, and timing 

requirements it should include, who 

should have access to it and in what 

manner, and how it would differ from 

part 78. Finally, we request comment on 

whether, similar to other programs 

identified in 40 CFR 78.1(a)(1), the 

agency should make the procedures of 

part 78 available to any actions of the 

Administrator under the comparable 

state regulations approved as a part of 

a state plan under the EGs. 

J. Consistency of Program Structure 

With Clean Air Act Authority 

The EPA is co-proposing two distinct 

forms of emissions trading as the 

mechanism for federal implementation 

of standards of performance that achieve 

the emission performance levels 

determined by application of the BSER 

in the Clean Power Plan EGs. Both 

proposals are ‘‘emission standard’’ 

approaches as defined in the EGs, and 

the EPA is not proposing an approach 

like the ‘‘state measures’’ approach that 

is also available to states in the final 

EGs. The EPA has legal authority to 

establish either of the proposed trading 

systems as a federal plan under CAA 

section 111(d)(2). We discuss this topic 

briefly here and invite public comment. 

The EGs discussed the role of emissions 

trading in the BSER, see, e.g., section 

V.A of the preamble to the final EGs. 

The EPA regards this to be a separate 

issue and is not revisiting or reopening 

the discussion of the BSER or the role 

of trading in the BSER here. The EGs 

recognize and provide ample 

opportunity for states to establish 

standards of performance that allow the 

use of emissions trading or other multiunit compliance approaches. Here we 

discuss why an emissions trading 

program is a lawful and appropriate 

form of federal ‘‘implementation’’ of a 

‘‘standard of performance’’ under CAA 

section 111(d)(2). We invite comment 

on this legal discussion and the agency’s 

interpretation of its authority. 

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

Section 111(d)(2) provides that ‘‘[t]he 

Administrator shall have the same 

authority [ ] 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 

in the case of failure to submit an 

implementation plan . . .’’ 42 U.S.C. 

7411(d)(2)(A).43

The phrase ‘‘same authority to 

prescribe’’ indicates that Congress 

viewed the EPA’s authority to issue a 

federal plan for designated pollutants 

under CAA section 111(d) as, in some 

sense, co-extensive with its authority to 

issue a FIP for National Ambient Air 

Quality Standards (NAAQS) pollutants 

under CAA section 110. This authority 

under CAA section 111, of course, must 

be understood in reference to the 

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

emission reductions for designated 

pollutants from designated facilities), 

rather than in reference to the purpose 

of CAA section 110 (i.e., to attain and 

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44We interpret the cross-reference to be to the 

currently enacted version of CAA section 110(c), 

rather than to a prior version. As discussed in 

section VII of this preamble, below, the current 

version of CAA section 110, including subsection 

(c), reflects changes made in the 1990 Amendments 

based on experience gained in the first two decades 

of the CAA’s implementation. The statute and 

legislative history do not expressly address the 

question, but there is no indication Congress would 

have intended to prevent these improvements from 

being available under CAA section 111 as well. 

maintain the NAAQS). However, it has 

been the agency’s longstanding view 

that, in both procedural and substantive 

respects, Congress intended that the 

CAA section 110 authority be looked to 

under CAA section 111(d)(2). See 40 FR 

53340, at 53342 (November 17, 1975) 

(‘‘It is obvious that [the Administrator] 

could only prescribe standards on some 

substantive basis. The references to 

section 110 of the CAA suggest that (as 

in CAA section 110) [she] was intended 

to do generally what the states in such 

cases should have done, which in turn 

suggests that (as in CAA section 110) 

Congress intended the states to 

prescribe standards on some substantive 

basis. Thus, it seems clear that some 

substantive criterion was intended to 

govern not only the Administrator’s 

promulgation of standards but also [her] 

review of state plans.’’). 

Over the several decades of 

implementation of the CAA, the courts, 

and the EPA, have addressed the nature 

and scope of CAA section 110 authority. 

See, e.g., 71 FR 25328, 25338 (May 12, 

2005) (CAIR final rule). In general, the 

EPA has broad power under CAA 

section 110(c) to cure a defective SIP. 

Thus, in promulgating a FIP under CAA 

section 110, the EPA may exercise its 

own, independent regulatory authority 

in accordance with CAA section 110(c) 

and the CAA more broadly. When the 

EPA has promulgated a FIP, courts have 

not required explicit authority for 

specific measures: ‘‘We are inclined to 

construe Congress’ broad grant of power 

to the EPA as including all enforcement 

devices reasonably necessary to the 

achievement and maintenance of the 

goals established by the legislation.’’ 

South Terminal Corp. v. EPA, 504 F.2d 

646, 669 (1st Cir. 1974). Further, the 

same authority that is exercised by the 

states under the CAA in connection 

with the adoption, implementation, and 

enforcement of a SIP may be assumed to 

be available to the EPA when the agency 

issues a FIP, after determining that a 

state has not adopted a satisfactory SIP. 

As the Ninth Circuit has held, when the 

EPA acts in place of the state pursuant 

to a FIP under CAA section 110(c), the 

EPA ‘‘stands in the shoes of the 

defaulting state, and all of the rights and 

duties that would otherwise fall to the 

state accrue instead to EPA.’’ Central 

Ariz. Water Conservation Dist. v. EPA, 

990 F.2d 1531, 1541 (9th Cir. 1993). 

Accord, South Terminal, 504 F.2d at 

668 (‘‘[T]he Administrator must 

promulgate promptly regulations setting 

forth an implementation plan for a state 

should the state itself fail to propose a 

satisfactory one. The statutory scheme 

would be unworkable were it read as 

giving to the EPA when promulgating an 

implementation plan for a state, less 

than those necessary measures allowed 

by Congress to a state to accomplish 

federal clean air goals. We do not adopt 

any such crippling interpretation.’’). 

By the same token, if there are clear 

limits to the EPA’s CAA section 110(c) 

authority, those too, would arguably 

carry over to CAA section 111(d)(2). For 

instance, CAA section 110(c)(1) ties the 

EPA’s authority to promulgate a final 

FIP for a state to the EPA’s predicate 

action on a SIP (or lack thereof): 

Generally, either an action disapproving 

a plan, or a finding that a state has failed 

to submit a plan. However, even here, 

as the Supreme Court has recognized, 

‘‘the plain text of the CAA grants EPA 

plenary authority to issue a FIP ‘at any 

time’ within the 2-year period that 

begins the moment EPA determines a 

SIP to be inadequate.’’ EPA v. EME 

Homer City Generation, 134 S. Ct. 1584, 

1602 n.14 (2014). 

Congress gave the EPA the same 

authority to prescribe a plan under CAA 

section 111(d)(2) as it possesses under 

CAA section 110(c). The EPA believes 

this authority is the ‘‘same’’ in the sense 

described above and in the case law.44

The scope of the EPA’s action to 

undertake a FIP under CAA section 110 

is informed by the scope of the state’s 

action to undertake a SIP; likewise, the 

scope of the EPA’s action to undertake 

a federal plan under CAA section 111(d) 

is informed by the scope of the state’s 

action to undertake a state plan. 

The agency received comments on the 

proposed EGs from commenters who 

stated that the EPA cannot require states 

to implement the building blocks that 

make up the BSER; for example, 

ordering re-dispatch to natural gas-fired 

units, or ordering the construction of RE 

projects. These commenters went on to 

say that the EPA itself would have no 

authority to order these types of actions 

under a federal plan. As we explained 

in the Legal Memorandum for the final 

EGs, and reiterate here, the premise of 

these comments is incorrect. The EPA is 

not requiring the implementation of the 

BSER or the building blocks in the EGs. 

Even where the EPA is directly 

implementing standards of performance 

in a federal plan, the agency will not, 

and need not, attempt to order sources 

to implement the measures that 

comprise the BSER. Rather, as set forth 

in the co-proposed federal plans 

discussed in sections IV and V of this 

preamble, the EPA would set emission 

standards for each of the affected EGUs 

in the federal plan state, provide 

mechanisms for their implementation 

and enforcement, and otherwise leave to 

the owners and operators of the affected 

EGUs the decisions about what 

measures they want to take to comply 

with the emission standard. Though the 

emission standards will be federally 

enforceable, as under a state plan, 

sources may achieve them through 

implementation of measures in the 

BSER, or any other method. 

Thus, the question whether the EPA 

would have the authority to directly 

order the implementation of the 

measures in the building blocks in this 

proposed federal plan is not only not 

relevant but represents a categorical 

misunderstanding of the nature of the 

BSER in relation to the imposition of 

standards of performance under a CAA 

section 111(d) plan. To illustrate this, by 

the same token the EPA could not 

enforce many logistical aspects of a 

control requirement such as a 

scrubber—for instance, the EPA does 

not need to assert the authority to order 

into existence companies that 

manufacture scrubbers, or order their 

construction or delivery on a certain 

schedule. The EPA need not in setting 

emission standards have before it all of 

the information regarding 

manufacturing, transportation of parts, 

or other logistical requirements to 

ensure that each scrubber gets 

constructed and delivered to a source. 

Similarly, the EPA here does not, and 

need not, propose an implementation 

approach of directly intervening to redispatch certain units, construct new RE 

projects, or take other measures, either 

included in the BSER or not. The agency 

determined the BSER and emission 

performance levels in the EGs on a 

reasonable assumption that all of those 

things can actually happen. In providing 

for the implementation of federally 

enforceable standards of performance in 

the federal plan proposed in this action, 

the agency is ensuring that these things 

will happen. 

2. Use of Market Techniques To 

Implement Standards of Performance 

Under the Clean Air Act 

The use of market techniques such as 

emission trading is well-supported in 

the CAA and has many regulatory 

precedents. The EPA discussed this 

history, and the reason why trading is 

a supportable method of 

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45The 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 DC Circuit because the court 

held it did not accomplish the objective of the Good 

Neighbor provision of the CAA, not because it used 

a trading approach per se. North Carolina v. U.S. 

EPA, 531 F.3d 896, 921 (D.C. Cir. 2008). More 

recently the Supreme Court upheld key portions of 

the CSAPR trading program that replaced CAIR in 

EPA v. EME Homer City, 134 S. Ct. 1584 (2014). 

46A copy of this memorandum has been placed 

in the docket for this rulemaking. 

implementation of standards of 

performance under CAA section 111(d) 

in the EGs. See section V.A of the final 

EGs. Here we supplement that 

discussion with respect to the agency’s 

own authority under CAA section 

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

implementation of a ‘‘standard of 

performance’’ in the federal plan. 

The 1990 CAA Amendments added 

broad authorizations for the use of 

market techniques in several sections of 

the statute, including Title I. States were 

provided express authority to use such 

approaches in their NAAQS 

implementation plans under CAA 

section 110(a)(2)(A): ‘‘Each [state] plan 

shall include enforceable emission 

limitations and other control measures, 

means, or techniques (including 

economic incentives such as fees, 

marketable permits, and auctions of 

emissions rights) . . . .’’ 42 U.S.C. 

7410(a)(2)(A). The EPA was given 

similar authority in the definition of a 

‘‘Federal Implementation Plan’’ in CAA 

section 302, which defines that term as 

an EPA-promulgated plan, which 

‘‘includes enforceable emissions 

limitations or other control measures, 

means or 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. 

7602(y). Section 111(d)(2) of the CAA 

provides the EPA the same authority to 

prescribe a federal plan under CAA 

section 111 as it would have to 

promulgate a FIP under CAA section 

110(c). Thus, the EPA believes the plain 

language of the statute authorizes the 

use of market techniques in CAA 

section 111(d) federal plans. 

However, even if one were to view 

this language as not wholly 

unambiguous with respect to the scope 

of federal authority under CAA section 

111, the EPA believes that CAA section 

111, in conjunction with authorizations 

and endorsements of market techniques 

throughout the CAA, and other indicia 

of congressional intent, strongly support 

the view that market techniques are 

within the EPA’s authority to 

promulgate a federal plan under CAA 

section 111(d). 

Case law throughout the history of the 

CAA has generally confirmed the legal 

viability of emissions trading as an 

implementation measure so long as the 

trading ultimately achieves the emission 

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

Sierra Club v. EPA, No. 12–3169 (6th 

Cir. Filed March 18, 2015), Slip Op. at 

11–14 (upholding EPA approval of 

redesignation of area to attainment on 

basis that reductions in emissions from 

cap-and-trade programs (NOX SIP Call, 

CAIR, and CSAPR) are permanent and 

enforceable). Chevron, U.S.A., Inc. v. 

Natural Res. Def. Council, Inc., 467 U.S. 

837 (1984) (‘‘Chevron’’), the seminal 

case establishing the Supreme Court’s 

standard of review of agency 

interpretations of the statutes they 

administer, upheld one of the EPA’s 

early emissions trading programs, the 

Netting Rules of 1980 (45 FR 52676; 

August 7, 1980), which the EPA in its 

discretion chose to allow states to apply 

in both attainment and nonattainment 

areas (46 FR 50766; October 14, 1981). 

The Netting Rules allowed existing 

major sources to modify without 

triggering certain requirements of PSD 

or nonattainment NSR, so long as any 

increase in emissions associated with 

the modification is compensated for by 

a corresponding decrease in emissions 

elsewhere within the same facility, such 

that there is no significant net increase 

in emissions from the facility as a 

whole. In upholding this approach in 

Chevron, the Supreme Court gave 

deference to the EPA’s definition of the 

term ‘‘source,’’ finding in that term 

sufficient ambiguity to support the 

agency’s reasoned application of an 

emissions averaging approach for total 

pollution emitted from the source. See 

EPA v. EME Homer City, 134 S. Ct. 1584, 

1603 (2014) (‘‘Because ‘a full 

understanding of the force of the 

statutory policy . . . depend[s] upon 

more than ordinary knowledge’ of the 

situation, the administering agency’s 

construction is to be accorded 

‘controlling weight unless . . . arbitrary, 

capricious, or manifestly contrary to the 

statute.’ ’’) (quoting Chevron, 467 U.S. at 

844).45

With the increasing recognition of the 

utility of trading, crediting, and 

averaging to meet emission reduction 

goals efficiently, the EPA set forth a 

comprehensive policy on trading in 

1986. Emissions Trading Policy 

Statement; General Principles for 

Creation, Banking and Use of Emission 

Reduction Credits, 51 FR 43814 

(December 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 CAA 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 

nonattainment areas. The agency 

emphasized the requirements of 

enforceability, tracking (and preventing 

double-counting), determining the 

appropriate baseline from which to 

measure emissions, and demonstration 

of actual air quality benefits. 

The use of an emissions trading 

system for CO2 reductions for affected 

EGUs under CAA section 111(d) is also 

analogous to the trading system for 

chlorofluorocarbons (CFCs) under the 

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 (April 14, 

1989) (hereinafter ‘‘OLC Memo’’).46 The 

OLC was asked by OMB to opine 

whether a general grant of regulatory 

authority to the EPA to ‘‘control’’ CFCs 

was sufficient to authorize an emissions 

fee or a cap-and-trade system, including 

auction, of tradable allowances. The 

statute authorized the EPA to issue 

regulations ‘‘for the control of any 

substance, practice, process, or activity 

(or any combination thereof) which in 

his judgment may reasonably be 

anticipated to affect the stratosphere, 

especially ozone in the stratosphere, if 

such effect in the stratosphere may 

reasonably be anticipated to endanger 

public health.’’ Former CAA 157(b) (as 

enacted in the 1977 CAA amendments). 

The Office of Legal Counsel concluded 

that this language—which it 

characterized as ‘‘plain,’’ 

‘‘unambiguous,’’ and ‘‘sweeping’’—was 

sufficient to authorize the EPA to 

establish a cap-and-trade program with 

auction for CFCs. See id. at 7 (‘‘It cannot 

seriously be argued that the use of 

economic incentives to regulate 

pollution is a novel or strange idea that 

could not have been anticipated by the 

authors of the Clean Air Act 

Amendments [of 1977].’’) (citing 

multiple examples from the policy 

literature as early as E. Mishan, The 

Costs of Economic Growth (1967)). The 

OLC noted that as of 1977, ‘‘Congress 

was cognizant of economic forms of 

regulation, did not prohibit them, but 

instead used general language 

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47U.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. 

48The 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. 

49The CAMR program was vacated because the 

EPA had not made requisite findings under CAA 

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

emissions of a hazardous air pollutants (HAP). No 

such procedural concern is present here with 

respect to CO2, which is not a HAP under CAA 

section 112. 

50We 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 CO2 emitted from 

affected EGUs. We address those concerns in the 

communities sections of the final EGs, at section IX, 

and in this preamble in section IX below. 

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 

SIPs and FIPs for NAAQS. See 42 U.S.C. 

7410(a)(2)(A), 7602(y). In the wake of 

the 1990 Amendments, the EPA issued 

an ‘‘Implementation Strategy for the 

Clean Air Act Amendments of 1990.’’ 47

This Strategy included as one of nine 

overarching implementation principles, 

‘‘Market-based: Use of market-based 

approaches and other innovative 

strategies to creatively solve 

environmental problems.’’ Further, it 

announced that the EPA would make 

‘‘full use of innovative market-based 

approaches,’’ and that the agency will 

supplement traditional approaches with 

broader use of market incentives and 

other innovative approaches ‘‘whenever 

possible.’’ Id. at 3, 9. 

Since the 1990 Amendments, the EPA 

has established three of its most robust 

trading programs—the Federal NOX

Budget Trading Program (65 FR 2674; 

January 18, 2000), the CAIR (71 FR 

25328; April 28, 2006), and the CSAPR 

(76 FR 48208; August 8, 2011), under 

CAA section 110(a)(2)(D)(i)(I), relating 

to air pollution that causes 

nonattainment or interference with 

maintenance of air quality standards in 

downwind states.48

As noted in the rulemaking action for 

the final EGs, the EPA has instituted or 

authorized the use of emissions trading 

programs twice in the past under CAA 

section 111(d). The EPA authorized 

NOX emissions averaging or trading 

within or between facilities under the 

Municipal Waste Combustors EGs in 

1995. 60 FR 65387, 65402 (December 19, 

1995) (codified at 40 CFR 60.33b(d)(1) 

and (2)). The EPA also developed a capand-trade system for mercury under 

CAA section 111(d) in the Clean Air 

Mercury Rule (CAMR). 70 FR 28606 

(May 18, 2005). The EPA proposed a 

federal plan for trading that was 

identical in all relevant respects to the 

CAMR rule. 71 FR 77100 (December 22, 

2006). However, CAMR was vacated by 

the D.C. Circuit on grounds unrelated to 

the establishment of a trading system for 

implementation before the CAMR 

federal plan could be finalized. New 

Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 

2008).49

The agency believes these legal and 

administrative precedents for federal 

trading programs under the CAA going 

back decades amply support its decision 

to propose two forms of emission 

trading as the method of 

implementation of the Clean Power Plan 

EGs in the federal plan. Notably, 

emissions trading is particularly 

appropriate with respect to a global 

pollutant such as CO2 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 CAA section 111(d) to 

select the method by which it would 

control CO2 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 GHG-producing sector 

cannot be prescribed in a vacuum: As 

with other questions of national or 

international policy, informed 

assessment of competing interests is 

required. Along with the environmental 

benefit potentially achievable, our 

Nation’s energy needs and the 

possibility of economic disruption must 

weigh in the balance. The CAA entrusts 

such complex balancing to the EPA in 

the first instance, in combination with 

state regulators.’’). 

This proposal is guided by the 

relevant cases and the experiences of 

the agency in implementing the CAA 

trading programs discussed above. The 

EPA invites comment on this discussion 

and the agency’s interpretation that 

CAA section 111(d)(2) authorizes the 

two approaches to a federal plan 

proposed here. 

IV. Rate-Based Implementation 

Approach 

A. Overview 

The EPA’s federal plan requirements 

for CO2 from affected EGUs implement 

the EGs as previously discussed. In this 

federal plan and model rule proposal 

the EPA is proposing, as one option, 

rate-based emission standards (i.e., the 

emission standard approach) for 

affected EGUs not covered by an 

approved state plan as specified in the 

Clean Power Plan. The EPA is proposing 

to apply the subcategorized emission 

rates in this federal plan proposal. 

These rate-based emission standards are 

consistent with, and would satisfy, the 

degree of emission limitation achieved 

by the BSER determination made in the 

final Clean Power Plan EGs, which 

included subcategorized CO2 emission 

performance rates for affected EGUs to 

meet during the plan performance 

periods. An affected EGU subject to this 

federal plan will demonstrate 

compliance by achieving a stack 

emission rate less than or equal to the 

rate-based emission standard or by 

applying ERCs, acquired by the EGU, to 

its measured stack emissions rate. The 

application of ERCs by an affected EGU 

to comply with an emission standard 

has been determined in the final Clean 

Power Plan as a mechanism available to 

affected EGUs with a CO2 emission rate 

greater than its respective performance 

rate to meet compliance obligations, see 

section VIII.K of the final EGs. Under a 

rate-based federal plan, the EPA would 

act as the state described in section 

VIII.C.1.a of the final EGs with the EPA 

acting as the issuer of ERCs, and 

otherwise implementing and enforcing 

the standards of performance for 

affected EGUs subject to the federal 

plan. 

This section describes the proposed 

rate-based federal plan and model 

trading rule and how each would be 

designed and operated, consistent with 

the EGs. For the federal plan, the EPA 

is proposing to limit the issuance of 

ERCs to designated categories of affected 

EGUs and to RE resources and nuclear 

generation (from new capacity and 

incremental capacity uprates) that are 

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51For simplicity, affected utility boilers and IGCC 

will collectively be called ‘‘steam generating units.’’ 

52Note that the values of limits and 

determinations made as the BSER are not open for 

comment. 

measured by a revenue quality meter, 

rather than the full suite of options 

discussed in the EGs. The EPA requests 

comment on whether to limit the scope 

of the federal plan in this manner, and 

if not, what other sources of low- or 

zero-emitting electricity in federal plan 

states should also be eligible to generate 

ERCs for compliance purposes. For both 

the proposed federal plan and model 

rule, the EPA requests comment on 

which EM&V plan, measurement and 

verification (M&V) report, and 

verification report requirements should 

apply for each eligible resource. Further 

discussion of non-BSER measures that 

may be eligible to generate ERCs can be 

found in the Clean Power Plan and 

section IV.C.3 of this preamble. (The 

EPA is not reopening its determination 

of the BSER.) 

B. Rate Goals 

In the Clean Power Plan the EPA 

identified a rate-based ‘‘emission 

standards’’ approach as an approvable 

method for state plans to implement the 

final EGs. In this approach the 

requirements for compliance rest solely 

on affected EGUs in the form of 

federally enforceable emission 

standards expressed as a rate of 

emissions of CO2 per unit of energy 

output. In the Clean Power Plan, the 

EPA established, through application of 

the BSER, separate CO2 emission 

performance rates for affected EGUs in 

two subcategories. The two 

subcategories are natural gas-fired 

stationary combustion turbines (i.e., 

natural gas combined cycle units, or 

NGCC units) and fossil fuel-fired EGUs 

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

CO2 emission performance rates set in 

the Clean Power Plan are reflected 

below in Table 6 of this preamble. The 

EPA is proposing to apply these rates in 

the rate-based federal plan as the 

emission standards for NGCC units, and 

SGUs, respectively. For a thorough 

discussion of affected EGU categoryspecific CO2 emission performance rates 

and rationale, see section VI of the final 

EGs. These calculated standards and the 

premises that these standards are based 

on are not within the scope of comment 

in this rulemaking as they were 

finalized in the Clean Power Plan. 

As discussed in section III.D of this 

preamble above, the EPA proposes to 

implement a compliance schedule for 

the rate-based federal plan with multiyear compliance periods as follows: A 3- 

year period (2022 through 2024), 

followed by a 3-year period (2025 

through 2027), followed by a 2-year 

period (2028 and 2029), for the Interim 

Period; and, commencing in 2030, 

successive 2-year compliance periods 

for the Final Period. In the Clean Power 

Plan, the EPA established CO2 emission 

performance rates for the subcategories 

of affected EGUs for the performance 

periods. The EPA proposes to use those 

emission performance rates 

promulgated in the Clean Power Plan as 

the rate-based emission standard for the 

respective EGUs that would become 

subject to this proposed federal plan if 

finalized. The EPA is not opening for 

comment the determinations made in 

the Clean Power Plan of each 

subcategorized CO2 emission 

performance rates. The rate-based 

emission standards for respective EGU 

types are provided for convenience in 

Table 6 of this preamble. 

The EPA is proposing to use a glide 

path during the Interim Period for EGUs 

to provide a smooth transition to the 

final compliance periods after 2030. 

This approach is established in the final 

EGs. In Table 6 of this preamble, the 

applicable standards for each interim 

compliance period are listed. 

TABLE 6—GLIDE PATH INTERIM PERFORMANCE RATES (ADJUSTED OUTPUT-WEIGHTED-AVERAGE POUNDS OF CO2 PER

NET MWh FROM ALL AFFECTED FOSSIL FUEL-FIRED EGUS) 

Technology 

2022–2024 

Compliance 

rate 

2025–2027 

Compliance 

rate 

2028–2029 

Compliance 

rate 

Final rate 

SGU or IGCC ................................................................................................... 1,671 1,500 1,380 1,305 

Stationary combustion turbine ......................................................................... 877 817 784 771 

The EPA is using the subcategorized 

rates in the rate-based trading approach 

because it allows ERCs to be fungible 

across jurisdictional borders and 

provides an incentive structure, as 

compared to other rate-based 

approaches, that facilitates 

implementation of measures identified 

as part of the BSER. Using 

subcategorized rates allows for: (1) 

Consistently applied emission rates for 

power plants of different types; and (2) 

free trading of fungible ERCs among all 

affected EGUs subject to the federal plan 

and within the federal trading program. 

The EPA solicits comments on whether 

the subcategorized rate approach is the 

preferred rate-based approach for the 

federal plan and model trading rule.52 If 

a subcategorized approach for a ratebased model rule and federal plan is not 

preferred by commenters, the EPA 

requests comment on the perceived 

benefits of an alternative rate or set of 

rates (e.g., applying a uniform rate, i.e., 

the state goal, to all affected units 

within the state as the EGUs’ emission 

standard). 

C. Crediting Mechanism 

Under a rate-based emission standard 

approach in the federal plan, we are 

proposing that EGUs subject to the 

emission performance requirements for 

GHGs will either need to emit at or 

below their rate-based emission 

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 ratebased emission standard. For each ERC, 

one MWh is added to the denominator 

of the reported CO2 emission rate, 

resulting in a lower adjusted CO2

emission rate. 

Under this proposed federal plan, 

ERCs will be issued by the EPA to four 

categories of entities: (1) Affected EGUs 

that perform at a rate below the 

applicable rate-based emission standard; 

(2) affected NGCC units for all 

generation (represents shifting 

generation from SGUs to NGCC units, as 

anticipated under Building Block 2); (3) 

new nuclear units and capacity uprates 

at existing nuclear units; and (4) RE 

providers that develop metered projects 

and programs whose results, in MWh, 

are quantified and verified according to 

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53The use of ERCs and definition as a compliance 

mechanism to meet the BSER emission performance 

rates is established in section VIII.K of the final 

EGs. 

54 It is assumed that any increase in NGCC 

generation above 2012 levels is displacing fossil 

fuel-fired steam EGU generation. 

55A 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. 

EM&V criteria as described below in 

section IV.D.8 of this preamble. We are 

also discussing in this preamble, 

requesting comment for the federal plan, 

and proposing for the model trading 

rule a potential fifth category: Other 

low- and zero-emitting non-BSER 

measures that are described in section 

IV.C.3 of this preamble. The concept of 

using an ERC as a crediting mechanism 

to meet compliance obligations is 

consistent with the Clean Power Plan 

EGs and is being adopted in this federal 

plan.53

Because the goal of this rulemaking is 

the actual reduction of CO2 emissions, 

it is fundamental that ERCs represent 

the MWh of energy generation or 

savings they purport to represent. To 

this end, only valid ERCs that actually 

meet the standards articulated in this 

rule may be used to satisfy any aspect 

of compliance by an affected EGU with 

emission standards. The responsibility 

for the validity of the ERC rests with the 

affected EGU. Despite safeguards 

included in the structure of ERC 

issuance and tracking systems, such as 

the review of eligibility applications and 

M&V reports, and EPA issuance of 

ERCs, ERCs may be issued that do not, 

in fact, represent eligible zero-emission 

MWh as required in the EGs. A variety 

of situations may result in such 

improper ERC issuance, ranging from 

simple paperwork errors to outright 

fraud. The EPA requests comment on 

ways that the EPA could safeguard the 

validity of an ERC. 

1. ERCs Generated and Owed Against a 

Standard 

The number of ERCs generated or 

needed for surrender by an affected 

fossil fuel-fired EGU is based on the CO2

emission rate of the EGU in comparison 

to a rate-based emission standard. The 

calculation of ERCs generated by an 

EGU or needed for compliance is the 

CO2 stack emission rate of the EGU 

subtracted from the standard the EGU is 

subject to, and this value is 

subsequently divided by the standard 

the EGU is subject to. This value is a 

normalized quantity of how much better 

or worse the EGU is performing 

compared to its standard. The 

normalized value is weighted by 

multiplying the MWh electricity output 

from the EGU at that emission rate. This 

can be generically expressed as: 

If the value calculated is positive, this 

indicates the number of ERCs that are 

being generated; conversely, a negative 

value indicates how many ERCs will 

need to be acquired to meet the unit’s 

emission rate for that compliance 

period. ERCs will be issued on an 

annual basis to ERC providers (i.e., 

entities generating ERCs via the ERC 

approval and issuance process detailed 

below). Surrender of ERCs for 

compliance by affected EGUs will not 

occur until the end of the compliance 

period as further described in section 

IV.D.10 of this preamble. 

As an example, assume a steam EGU 

operating in the second interim 

compliance period is subject to a rate 

standard of 1,500 lbs CO2/MWh. 

Assume it operates at 2,000 lbs CO2/

MWh, and also assume it generates 1 

million MWh over a compliance period. 

Its total emission rate would be 2 billion 

lbs CO2/1 million MWh. In order to 

achieve the emission standard, it would 

need to purchase 333,334 ERCs 

(rounded to the nearest higher integer). 

In essence, this quantity of ERCs 

represents the quantity of MWh that 

need to be added to the steam EGU’s 

denominator (i.e., generation, here, 1 

million MWh), such that 2 billion 

pounds of CO2 (total emissions), divided 

by total generation (i.e., in this case, 

1,333,334 MWh) equals the emission 

rate for compliance (1,500 lbs/MWh). 

The discussion in this subsection 

builds on and applies the definition, 

benefits, use, and determination of 

using ERCs from the final EGs (section 

VIII of the final EGs). We invite 

comment on use of the approach just 

described as a method of 

implementation of a federal plan and a 

model trading rule, and we request 

comment on any alternatives to this 

approach that still fall within the 

established criteria described in the 

Clean Power Plan EGs. Comments that 

solely relate to determinations finalized 

in the EGs will be considered outside 

the scope of this proposed rule. 

2. Incremental NGCC ERCs 

Building Block 2 (BB2) of the BSER 

determination in the Clean Power Plan 

EGs describes shifting generation from 

SGUs to NGCC units because NGCC 

units generate electricity at a less carbon 

intensive rate. BB2 describes NGCC 

units generating at 75 percent of the 

unit’s annual operating capacity. This 

level of generation, for most NGCC 

units, would represent an increase in 

annual generation from a 2012 baseline. 

For every hour of electricity generated 

by an NGCC unit beyond its 2012 

baseline (i.e., incremental generation), 

there is a corresponding emission 

reduction in the power system.54 The 

EPA is proposing to reflect the emission 

reductions of BB2 by crediting all NGCC 

generation on a pro rata basis that 

reflects expected incremental NGCC 

generation to 75 percent capacity. This 

means that for every hour that an NGCC 

unit generates electricity, it will also 

generate a partial credit associated with 

the generation shift from fossil steam to 

NGCC units. The NGCC unit will 

generate a partial credit because the 

emission reductions associated with 

BB2 have been distributed on an hourly 

basis. A discussion on the concepts 

behind the distribution of emission 

reductions of incremental NGCC 

generation on an hourly basis can be 

found at the end of this subsection. 

All affected NGCC generation will be 

credited, with ERCs, by a factor that 

represents the described emission 

reductions from incremental generation; 

ERCs credited in this way will be 

designated as Gas Shift ERCs (GS–ERCs) 

for clarity.55 The collective sum of the 

GS–ERCs generated realizes the amount 

of emission reductions described in BB2 

when 75 percent capacity is achieved. 

This incentive is not a requirement, 

however. If NGCC units do not 

collectively increase to 75 percent 

capacity or above, the lost opportunity 

for ERC generation simply will need to 

be achieved through other means (e.g., 

emissions performance improvements at 


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56The regions that are used in the Clean Power 

Plan EGs and for this proposal are the Eastern 

Interconnect, Western Interconnect, and Electric 

Reliability Council of Texas (ERCOT). 

57Note that per the discussion in section VI of the 

final EGs, if the EPA had measured incremental 

NGCC generation for reassignment to fossil steam 

rate as the difference from the post building block 

three levels and full utilization, the post building 

block three levels would be used in the numerator 

here, resulting in a higher ‘‘incremental generation 

factor’’ and more ERCs for the same amount of 

NGCC generation. 

affected EGUs or additional RE 

generation). The amount of GS–ERCs 

the EPA proposes to be generated for 

every MWh of NGCC operation is set at 

a factor relating the amount of 

electricity generation that NGCC units 

collectively would generate at the level 

described in BB2 (i.e., reaching 75 

percent capacity) and the associated 

emission reductions. This means that 

fractional GS–ERCs are generated for 

every NGCC MWh and when the 

interconnect region collectively reaches 

the level that would be generated if all 

NGGC units in the region operated at a 

75 percent capacity factor there will be 

an amount of GS–ERCs that correlates to 

the emission reductions anticipated 

under BB2 of the BSER. NGCC units are 

expected to be incentivized to reach this 

level of generation in part due to market 

demand for GS–ERCs. Thus, GS–ERCs 

have the potential to play an important 

role in the sector meeting compliance 

obligations. 

The number of GS–ERCs that an 

NGCC unit generates is a combination of 

three factors. The first is the GS–ERC 

Emission Factor. This emission factor 

represents how much better an 

individual NGCC’s emission rate is 

compared against the fossil steam 

standard. This measures the emission 

reductions because of the BB2 shift in 

generation. The SGU standard used as 

reference here is as described above in 

section IV.B of this preamble and 

established in the BSER determination 

from the EGs of the least stringent 

region 56 (i.e., the region with the 

highest calculated rate-based emission 

standard for SGUs). The GS–ERC 

Emission Factor is expressed by taking 

the complement of the ratio of the 

NGCC standard to the fossil-steam 

standard. It can be summarized by the 

following expression: 

The second factor is the Incremental 

Generation Factor. This factor 

represents the distribution of the 

increased NGCC generation across all 

NGCC generation. In essence, it is 

prorating the incremental NGCC 

generation over all NGCC generation. 

The Incremental Generation Factor is 

calculated by taking the number of 

MWh beyond the 2012 baseline needed 

for the corresponding region to reach 75 

percent NGCC generation capacity and 

dividing it by the MWh that is 75 

percent NGCC generation capacity, 

giving a factor. This factor can be 

summarized by the following 

expression: 

The Incremental Generation Factor is 

a factor that the EPA will calculate and 

will be calculated for every compliance 

period based on the least stingent 

region’s Incremental Generation Factor 

based on increased utilization of RE and 

its replacement of fossil fuel-fired 

generation (based on Building Block 3 of 

the Clean Power Plan EGs).57 For the 

calculation of this factor the EPA is 

using the least stringent region for each 

compliance period and applying it for 

all GS–ERC calculations subject to the 

federal plan. The calculations for 

determinating the least stringent 

regional Incremental Generation Factor 

can be found in the GS–ERC TSD. Table 

7 of this preamble presents the proposed 

values that would apply for all NGCC 

units to calculate the amount of issued 

GS–ERCs. 

TABLE 7—INCREMENTAL GENERATION FACTORS FOR INTERIM AND FINAL COMPLIANCE PERIODS

Corresponding incremental generation factor 

Compliance period 1 

2022–2024 

Compliance period 2 

2025–2027 

Compliance period 3 

2028–2029 2030–2031 and thereafter 

0.22 0.32 0.28 0.26 

The third factor in calculating an 

NGCC unit’s generaton of GS–ERC is the 

NGCC Generation. The NGCC 

Generation is the total net energy output 

generation of the affected NGCC unit 

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 unit 

will generate. The Incremental 

Generation Factor and GS–ERC 

Emission Factor combine to make the 

GS–ERC generating rate for the NGCC 

unit. 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 GS–ERCs generated by the NGCC 

unit 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 


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allowing NGCC units to bid into the 

electricity market without having to 

adjust bids based on a projection of 

whether or not the NGCC unit will have 

generation incremental to its baseline in 

a given year. The proposed method also 

promotes the best performers within the 

NGCC subcategory by crediting them 

with a higher rate of generating GS– 

ERCs, as shown by the calculations 

above. The better the emission 

performance of an NGCC unit, the more 

GS–ERCs it is capable of earning per 

MWh. The proposed method also 

promotes and incentivizes all NGCC 

units, regardless of historical generation, 

to continue to operate at a greater 

capacity to replace steam generation. 

The EPA believes that this will allow for 

more fluidity in the market and 

flexibility for greater NGCC generation. 

In the Clean Power Plan the BSER 

determination for subcategory rates is 

calculated by using the least stringent 

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 unit’s GS–ERC 

calculation at a national level (i.e., 

applying the GS–ERC calculation 

components that generate the most GS– 

ERCs for every MWh). The EPA solicits 

comment on applying the least stringent 

regional factor to calculate GS–ERCs for 

all affected NGCC units subject to the 

federal plan and model rule on a 

national level. Conversely, the EPA also 

requests comment on applying, for each 

region, its own regional GS–ERC 

generation rate. As proposed, the least 

stringent region could change from 

compliance period to compliance 

period. The EPA requests comment on 

whether a single ‘‘least stringent’’ region 

should be chosen and used for 

calculations or whether being ‘‘least 

stringent’’ should be evaluated on a 

compliance period by compliance 

period basis. The EPA also requests 

comment on whether ‘‘least stringent’’ 

should be evaluated on a year-to-year 

basis. 

The EPA also requests comment on 

whether the GS–ERC Emission Factor 

should be calculated on a unit by unit 

basis (as currently proposed) or be 

calculated based on the least stringent 

region’s baseline 2012 average emission 

rate. This will simplify the practice of 

calculating and distributing GS–ERC 

generation, but would not reward the 

better performing NGCC units within 

the subcategory. In the GS–ERC TSD, 

the EPA used the regions’ average 

emission rate to calculate a factor that 

would credit GS–ERCs to all NGCC 

units subject to the federal plan. For 

2030 and beyond, this value is based on 

the Eastern Interconnect and is 0.08 GS– 

ERCs/MWh. So for every MWh that an 

NGCC unit generates it would be issued 

0.08 GS–ERCs and, if this were the 

approach the EPA proposed, this would 

apply to every NGCC unit that would be 

subject to the federal plan. 

In the GS–ERC TSD, the spreadsheet 

can be manipulated to show what an 

individual NGCC unit’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 unit’s emission 

rate instead of the average NGCC 

emission rate. 

The calculation of GS–ERCs for an 

NGCC unit is independent of the 

calculation of ERCs generated or owed 

against the NGCC standard. It is possible 

that an NGCC unit will owe ERCs 

against its assigned emission standard 

for every MWh generated, but still be 

generating GS–ERCs. GS–ERCs may 

only be used to meet steam generation 

units’ compliance obligations. 

As an example, an NGCC unit is 

connected to the grid and generates 1 

million MWh of electric output for the 

first year of the final performance 

period. During this year it emits 850 

million lbs of CO2 giving it an emission 

rate of 850 lbs CO2/MWh. The NGCC 

unit is subject to a Final Period 

emission rate limit of 771 lbs CO2/MWh. 

Since the NGCC unit is always subject 

to its NGCC rate-based emission 

standard of 771 lbs/MWh and it is 

operating at a rate above that standard 

it will owe non GS–ERCs for its own 

compliance. The ERCs owed are 

calculated by solving for the number of 

ERC MWh the NGCC unit will need to 

adjust its rate down to its emission rate 

limit. This is shown in the following 

equation: 

850,000,000 lbs CO2/[1,000,000 MWh + 

ERC MWh] = 771 lbs CO2/MWh 

When that equation is solved for the 

number of ERC MWh needed, the NGCC 

unit would need to acquire 102,464 

ERCs to adjust its emission rate to its 

rate-based emission standard. 

Additionally, the GS–ERC Emission 

Factor for this NGCC unit is calculated 

by using 771 lbs CO2/MWh for the 

NGCC emission rate and 1,404 lbs CO2/ 

MWh for the SGU emission standard in 

the equation described above. 

This calculation results in a GS–ERC 

Emission Factor of 0.45. This is only an 

example. Because the Incremental 

Generation Factor is calculated by the 

EPA, it can be found in the GS–ERC 

TSD and is proposed to be 0.26. By 

using the GS–ERC Emission Factor and 

Incremental Generation Factor 

calculated above with the NGCC unit’s 

generation for the year, the number of 

GS–ERCs for this NGCC unit can be 

calculated. 

0.45 * 0.26 * 1,000,000 = GS–ERC 

The calculation results in 117 

thousand GS–ERCs being generated. 

Because an NGCC unit cannot use the 

GS–ERCs it generates to meet its 

compliance obligations, this NGCC unit 

will both generate ERCs (117,000 GS– 

ERCs) and owe ERCs (102,464 non-GS– 

ERCs against NGCC standard). This 

NGCC unit may sell (or otherwise 

transfer) or bank its GS–ERCs. If a GS– 

ERC is sold, those proceeds may, in 

turn, be used to acquire non-GS–ERCs to 

satisfy the NGCC unit’s compliance 

obligations. 

A GS–ERC may not be used to meet 

an NGCC unit’s compliance obligation 

because they are generated to reflect 

incremental NGCC generation replacing 

a SGU’s generation. The calculation to 

derive a GS–ERC represents this 

generation shift. If a GS–ERC were to be 

used for compliance for an NGCC unit 

it would represent a shift from one 

NGCC unit to another, which serves 

little purpose in achieving emission 

reductions. 

The EPA requests comment on the 

proposed approach and requests 

comment and suggestions on other 

approaches for existing NGCC units to 

generate GS–ERCs at all times. The EPA 

is considering this methodology that 

GS–ERCs are generated for all NGCC 

generation because it ensures that all 

existing NGCC units are encouraged to 

run at a greater capacity. The EPA 

requests comment on alternative 

methods to account for NGCC units 


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58This treatment for RE as an eligible measure 

type is also proposed for the set-aside for RE that 

is part of the proposed mass-based implementation 

approach co-proposed in section V of this preamble 

as the federal plan, and all proposed aspects of the 

eligible measure types described in this section and 

the requests for comment included below also 

apply in the mass-based set-aside context. 

Incremental nuclear is not eligible for the RE setaside. The set-aside method and the use of this 

eligibility treatment within it are specified in 

section V.D.3 of this preamble. 

generating GS–ERCs. Specifically, the 

EPA solicits comment on NGCC units 

generating GS–ERCs once a threshold of 

electric generation for the year is 

exceeded. This threshold is based on 

2012 as a baseline and any NGCC 

generation beyond this threshold would 

be considered incremental generation. 

There are two different options to 

evaluate against a baseline. The first is 

on a unit-level, if an NGCC unit 

generates more than it did in 2012, all 

generation above the 2012 level (i.e., 

incremental generation) is eligible to be 

credited with GS–ERCs. The other 

threshold option is to use a percentage 

threshold. Evaluated on a regional level, 

the 2012 baseline capacity percentage 

for NGCC units in the least stringent 

region is applied to all units. Each unit 

is considered to be incrementally 

generating after it exceeds the capacity 

percent and will be credited with GS– 

ERCs accordingly. The GS–ERCs in 

these instances are calculated by the 

following equation: 

This equation quantifies the 

reductions of the generation shift from 

fossil steam to NGCC units by the NGCC 

operating rate being evaluated against 

the fossil steam standard. For all 

incremental NGCC generation the NGCC 

operating rate is compared against two 

different standards: (1) The NGCC 

standard against which ERC generation 

is evaluated; and (2) the steam standard 

against which GS–ERC generation is 

evaluated. An evaluation against each 

standard is independent of one another 

and GS–ERCs, in this situation, are only 

available for fossil steam compliance 

purposes. 

While having a baseline threshold for 

EGU generation to credit GS–ERCs 

against closely resembles the EPA’s 

BSER determination, it enables a system 

in which GS–ERCs can be generated by 

replacing NGCC generation from one 

unit with NGCC generation from 

another. In this situation there is not 

necessarily any additional NGCC 

generation as a subcategory, but a shift 

in which NGCC units are generating 

electricity and to what degree. This 

allows for a situation in which GS–ERCs 

can be generated without achieving the 

anticipated reductions in CO2

emissions. 

The EPA also requests comment on 

whether a distinct type of ERC that 

comes with the proposed restrictions 

(i.e., GS–ERCs) is necessary to maintain 

the integrity of the rate-based trading 

proposal. Comments regarding this 

section that solely relate to 

determinations finalized in the EGs will 

be considered outside the scope of this 

proposed rule. 

3. Eligible Emission Reduction 

Measures for ERC Generation 

Under the rate-based federal plan, the 

EPA is proposing to specify emission 

reduction measures used to adjust an 

emission rate that are eligible for ERC 

issuance under the federal plan. 

Specifically, the EPA is proposing that 

RE generation that meets the 

requirements for eligible resources in 

the EGs (as specified in section VIII.K of 

the final EGs), meets all other 

requirements related to ERC issuance in 

the EGs and this proposal, and falls into 

one of the following specific categories 

of RE resources (as specified in section 

V.E of the final EGs), are eligible to be 

issued ERCs: Wind, solar, geothermal 

power, and hydropower.58 Further, the 

EPA is proposing for the federal plan 

that new nuclear units and capacity 

uprates at existing nuclear units that 

meet the requirements for eligible 

resources in the EGs (as specified in 

section VIII.K of the final EGs) and all 

other requirements related to ERC 

issuance in the EGs and this proposal 

are eligible to generate ERCs. Further, 

these RE and nuclear measures must 

have the ability to provide data from a 

revenue quality meter, a requirement 

that is further discussed in section 

IV.D.8 of this preamble. 

The EPA is proposing the inclusion of 

these measure types in the federal plan 

for the following reasons. These 

technologies, with the exception of 

nuclear, are part of the quantification of 

RE generation potential for the BSER. 

Thus, they are included in the 

quantification of CO2 emission 

performance rates and should be 

available to affected EGUs to meet their 

CO2 emission performance rate under 

the federal plan. See the final EGs for 

details on the treatment of these 

measures in BSER (see section V.E of 

the final EGs). These RE technologies 

are also expected to be able to deploy 

on an economic basis during the 

compliance period, as discussed in the 

final EGs (see section V.E.6 of the final 

EGs). These technologies also provide 

the simplest and most timely path for 

EM&V implementation under a federal 

plan, because they can use their existing 

metering infrastructure to quantify 

generation and submit it for ERC 

issuance. A concern unique to federal 

plan implementation is the need for an 

ERC issuance process that can be 

implemented in a streamlined manner 

across many jurisdictions in the time 

frame allowed by the federal plan while 

still assuring a rigorous EM&V process. 

By limiting eligibility to measures that 

can be directly metered, a feasible 

federal plan process for ERC issuance 

across a potentially large number of 

jurisdictions is ensured. This approach 

would allow for easier determinations of 

compliance with the requirements for 

EM&V proposed in section IV.D.8 of this 

preamble below (see also section 

VIII.K.3 of the final EGs). 

The agency requests comment on the 

inclusion of other emission reduction 

measures as eligible for ERC issuance 

under the rate-based federal plan. This 

may include other RE technologies not 

included above, such as distributed RE 

generation and various types of biomass. 

In this proposal, the EPA is also offering 

for comment a treatment option for 

biomass fuels, if it is included as an 

eligible measure under the federal plan 

(see below). 

The EPA requests comment on the 

inclusion of various types of demandside EE as eligible measures for ERC 

issuance under the federal plan, such as 

state and utility EE programs, projectbased demand-side EE, state building 

codes, state appliance standards, and 

conservation voltage reduction. The 

agency also requests comment on the 

inclusion of CHP as an eligible measure 

under the federal plan. Later in this 

section, the agency has provided 

detailed requirements for the issuance 

of ERCs for CHP, and we request 

comment on these requirements for 

inclusion in the federal plan. 

The EPA requests comment on the 

inclusion as eligible for ERC issuance 

under the federal plan of any other 


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59Types of waste-derived biogenic feedstocks 

may include: Landfill gas generated through the 

decomposition of municipal solid waste (MSW) in 

a landfill; biogas generated from the decomposition 

of livestock waste, biogenic MSW, and/or other 

food waste in an anaerobic digester; biogas 

generated through the treatment of waste water, due 

to the anaerobic decomposition of biological 

materials; livestock waste; and the biogenic fraction 

of MSW at waste-to-energy facilities (as discussed 

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

60Some 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 highquality 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 renewable portfolio standard 

(RPS), which, among other requirements, limits old 

growth forest harvests. 

61Specifically, the SAB found that ‘‘There are 

circumstances in which biomass is grown, 

harvested and combusted in a carbon neutral 

fashion but carbon neutrality is not an appropriate 

a priori assumption; it is a conclusion that should 

be reached only after considering a particular 

feedstock’s production and consumption cycle. 

There is considerable heterogeneity in feedstock 

types, sources and production methods and thus 

net biogenic carbon emissions will vary 

considerably. Of course, biogenic feedstocks that 

displace fossil fuels do not have to be carbon 

neutral to be better than fossil fuels in terms of their 

climate impact.’’ http://www.epa.gov/

climatechange/ghgemissions/biogenicemissions.html. 

62http://www.epa.gov/sab. 

emission reduction measures beyond 

those mentioned here, as long as they 

meet the eligibility requirements 

outlined in the final EGs for rate-based 

crediting. For all of the above measures 

on which the EPA requests comment, 

the agency is particularly interested in 

comments on how EM&V methods can 

be implemented for these measures 

across applicable jurisdictions in the 

timeframe provided by this proposal in 

a way that is rigorous, straightforward, 

widely demonstrated, and in accordance 

with the EM&V requirements in this 

proposal, outlined in section IV.D.8 of 

this preamble, and within the 

requirements outlined in the final 

Guidelines (see section VIII.K.3 of the 

final EGs). It should also be noted that 

any eligible measure will be subject to 

the eligibility requirements outlined in 

this proposal and the final EGs, 

including the requirement that the 

measure be incremental to 2012. 

The EPA acknowledges that as new 

technologies mature, there should be an 

avenue to add new technologies to this 

specified set of eligible measures under 

the federal plan. The agency requests 

comment on appropriate processes 

through which, after the federal plan is 

finalized, the EPA or stakeholders could 

demonstrate the appropriateness of new 

measure types and the EPA could 

evaluate and approve the demonstration 

so that a new measure type could be 

considered eligible for ERC issuance 

under the federal plan. 

Under the rate-based model rule, the 

EPA is proposing that any emission 

reduction measure is eligible as long as 

the requirements for eligible resources 

in the final EGs (as specified in section 

VIII.K of the final EGs) and all other 

requirements related to ERC issuance 

under the model rule that are specified 

in the EGs and this proposal. In 

particular, these measures should be 

able to meet the requirements for EM&V 

as finalized in the final EGs section 

VIII.K and those proposed for the model 

rule in section IV.D.8 of this preamble. 

In this section, the EPA is also 

providing detailed requirements for 

CHP and waste heat power (WHP); these 

requirements are proposed under the 

model rule, and we request comment on 

their inclusion in the federal plan. We 

are requesting comment on the 

inclusion of biomass and an option for 

the treatment of biomass in both the 

proposed rate-based federal plan and 

proposed rate-based model rule. 

As mentioned above, the EPA 

requests comment on the inclusion of 

biomass as an eligible measure for ratebased crediting. The EPA is also 

requesting comment on the following 

treatment option for biomass if biomass 

is included as an eligible measure. In 

the final EGs, the EPA recognizes that 

the use of some biomass-derived fuels 

can play an important role in 

controlling increases of CO2 levels in 

the atmosphere (see section VIII.I.C of 

the final EGs). The use of some kinds of 

biomass has the potential to offer a wide 

range of environmental benefits, 

including carbon benefits. However 

these benefits can typically be realized 

only if biomass feedstocks are sourced 

responsibly and attributes of the carbon 

cycle related to the biomass feedstock 

are taken into account. Many states have 

already recognized the importance of 

waste-derived feedstocks via mandatory 

and voluntary programs supporting 

such efforts.59 Some states have also 

acknowledged the potential role of 

certain forestry and agricultural 

industrial byproducts (such as black 

liquor) in energy production. Many 

states have also recognized the 

importance of forests and other lands for 

climate resilience and mitigation, and 

have developed a variety of sustainable 

forestry policies, biomass-related RE 

incentives and standards, and GHG 

accounting procedures.60

In addition to acknowledging such 

state programs, the EPA has undertaken 

a technical assessment of biogenic CO2

emissions from stationary sources 

associated with the production, 

processing and use of biomass fuels. In 

November 2014, the agency released a 

second draft of the technical report, 

Framework for Assessing Biogenic 

Carbon Dioxide for Stationary Sources. 

The revised Framework, and the EPA’s 

Science Advisory Board (SAB) peer 

review of the 2011 Draft Framework, 

concluded that it is not scientifically 

valid to assume that all biogenic 

feedstocks are ‘‘carbon neutral’’ and that 

the net biogenic CO2 atmospheric 

contribution of different biogenic 

feedstocks generally depends on various 

factors related to feedstock 

characteristics, production, processing 

and combustion practices, and, in some 

cases, what would happen to that 

feedstock and the related biogenic 

emissions if not used for energy 

production.61 The EPA is engaging in a 

second round of targeted peer review on 

the revised Framework with the SAB in 

2015.62 Information in the revised 

Framework and the second SAB peer 

review process, including stakeholder 

comments, will assist the EPA in 

assessing potential qualified biomass 

feedstocks in federal plan applications. 

If biomass is included as an eligible 

measure, we are taking comment on an 

option for biomass treatment under the 

rate-based federal plan, which would 

also potentially apply to eligible 

generation under the proposed massbased model trading rule allowance setaside and to the calculation of covered 

emissions for affected EGUs that are cofiring biomass. 

This option offered for comment is to 

specify a list of pre-approved qualified 

biomass fuels. For example, the EPA 

could recognize the CO2 and climate 

policy benefits of waste-derived 

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

industrial byproduct feedstocks (e.g., 

black liquor or other forestry and 

agricultural industrial byproducts with 

no alternative markets). As another 

example, the EPA could also recognize 

biomass feedstocks from sustainably 

managed forest lands, provided that 

these feedstocks meet certain 

requirements such as demonstration 

that the feedstock is sourced from 

sustainably managed lands (for 

example, feedstocks from forest lands 

with sustainable practices like improved 

management to increase carbon 

sequestration benefits) and therefore 

helps control increases of CO2 in the 

atmosphere. The pre-approved qualified 

biomass feedstocks list could be 

amended in the future as the science 

related to biogenic CO2 emissions 

assessments evolves. The EPA asks for 

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63The accounting treatment described in this 

section is for a ‘‘topping cycle’’ CHP unit. A topping 

cycle CHP unit refers to a configuration where fuel 

is first used to generate electricity and then heat is 

recovered from the electric generation process to 

provide additional useful thermal and/or 

mechanical energy. A CHP unit can also be 

configured as a ‘‘bottoming cycle’’ unit. In a 

bottoming cycle CHP unit, fuel is first used to 

provide thermal energy for an industrial process 

and the waste heat from that process is then used 

to generate electricity. Some waste heat power 

(WHP) units are also bottoming cycle units and the 

accounting treatment for bottoming cycle CHP units 

is provided with the WHP description below. 

64The applicable CO2 rate-based emission 

standard is in Table 6 of this preamble. 

65This term generally represents the thermal 

energy associated with the total fuel input. 

66The fuel emission factor can be determined 

through 40 CFR part 75 Appendix G. 

comment on whether to include a 

provision that allows sources to seek 

approval for other types of biomass to be 

added to the pre-approved list and what 

that process would entail. For example, 

this process could include consideration 

of the production, processing and use of 

forest- and agriculture-derived biomass 

fuels and related CO2 benefits. 

The EPA also requests comment on 

options for how EGUs would 

demonstrate that feedstocks meet the 

requirements to be accepted as a preapproved qualified biomass feedstocks. 

These requirements could include 

demonstration of certification or 

verification of practices that are 

additional to other monitoring, 

reporting and EM&V requirements 

discussed in this proposal, such as 

provision of sufficient credible analysis 

of carbon benefits, third party 

verification and/or certification, or a 

determination of the net biogenic CO2

effects related to the production, 

processing and use of the feedstock. 

The EPA requests broad comment on 

the types of qualified biomass 

feedstocks that should be specified in 

the final model rule, if any. We request 

comment on the methods that we 

should specify in the final model rule 

for the measurement of the associated 

biogenic CO2 for such feedstocks, as 

well as what other requirements we 

should specify in the final model rule 

related to biomass. Specifically, we seek 

comment on the level of detail provided 

and whether more or less detail (and 

what detail) should be included in the 

final model rule. We request comment 

on any other requirements that should 

be included in the final model rule 

regarding EM&V for qualified biomass. 

Discussion of the biomass EM&V 

requirements in the rate-based model 

rule can be found in section IV.D.8 of 

this preamble below. 

The eligibility requirements for ERC 

resources discussed in this section meet 

the requirements outlined in the final 

EGs (see section VIII.K.2 of the final 

EGs). The agency in this proposal is 

including in the regulatory text for the 

model rule language related to the 

crediting of these other potential ERC 

resources, even though they are not 

being proposed as a part of the federal 

plan. Our intent is to provide states 

further direction through the model rule 

on how states may include this broader 

set of ERC-generating resources in a 

rate-based plan. To reduce confusion 

over the applicability of these 

provisions, the agency has added a note 

in the regulatory text to clarify that 

these resources, and provisions 

throughout the proposed subpart that 

are related to those resources, are not 

applicable in the case of a federal plan. 

Rather they are proposed as part of the 

model trading rule only. However, 

again, the agency requests comment on 

the inclusion of these resources in the 

federal plan. 

The EPA is proposing with respect to 

the rate-based model rule that CHP units 

are eligible to generate ERCs. With 

respect to the federal plan, the EPA 

requests comment on the incorporation 

of non-affected CHP units. Electric 

generation from non-affected CHP 

units 63 may be used to adjust the CO2

emission rate of an affected EGU, as 

CHP units are low-emitting electric 

generating resources that can replace 

generation from affected EGUs. 

Electrical generation from non-affected 

CHP units that meet the eligibility 

criteria under section VIII.K.1.a of the 

Clean Power Plan preamble can be used 

to adjust the reported CO2 emission rate 

of an affected EGU. 

The electrical generation from a nonaffected CHP unit that can be used to 

adjust the CO2 emission rate of an 

affected EGU must be calculated in 

accordance with the method specified 

in this section. The CHP unit’s electrical 

output is prorated based on the CO2

emission rate of the electrical output 

associated with the CHP unit (a CHP 

unit’s ‘‘incremental CO2 emission rate’’) 

compared to a reference CO2 emission 

rate.64 This ‘‘incremental CO2 emission 

rate’’ related to the electric generation 

from the CHP unit would be relative to 

the applicable CO2 rate-based emission 

standard for affected EGUs in the state 

and would be limited to values between 

0 and 1. The CHP unit’s electrical 

output is prorated as follows: 

Prorated MWh = (1-incremental CHP 

electrical emission rate/applicable 

affected EGU rate-based emission 

standard)* CHP MWh output 

Where the ratio is limited to values 

between 0 and 1. 

The CHP electrical CO2 emission rate 

is the net emission rate when the CHP 

unit’s CO2 emissions related to its 

thermal output are deducted from the 

CHP unit’s total CO2 emissions. The 

CHP electrical CO2 emission rate is 

derived as follows: 

CHP electrical CO2 emission rate = [CHP 

fuel input 65 * fuel emission 

factor 66 ¥ (UTO/boiler efficiency) 

* fuel emission factor]/CHP 

electrical MWh 

Where UTO is the useful thermal 

output from a counterfactual industrial 

boiler that would have existed to meet 

thermal load in the absence of the CHP 

unit. 

This accounting approach takes into 

account the fact that a non-affected CHP 

unit is a fossil fuel-fired emission 

source, as well as the fact that the 

incremental CO2 emissions related to 

electrical generation from a non-affected 

CHP unit are typically very low. To 

generate ERCs for CHP, the CHP 

Electrical CO2 Emission Rate that is 

calculated (from above) is applied 

against the applicable affected EGU 

standards in the same fashion as 

described in section IV.C.1 of this 

preamble. The low CO2 emission rate for 

electrical generation from a non-affected 

CHP unit is a product of both the fact 

that CHP units are typically very 

thermally efficient and the fact that a 

portion of the CO2 emissions from a 

non-affected CHP unit would have 

occurred anyway from an industrial 

boiler used to meet the thermal load in 

the absence of the CHP unit. In contrast, 

the CHP unit also provides the benefit 

of electricity generation while resulting 

in very low incremental CO2 emissions 

beyond what would have been emitted 

by an industrial boiler. As a result, the 

accounting method does not presume 

that emission reductions occur outside 

the electric power sector, but instead 

only accounts for the CO2 emissions 

related to the electrical production from 

a CHP unit that is used to substitute for 

electrical generation from affected 

EGUs. 

The EPA is proposing with respect to 

the rate-based model rule that WHP 

units are eligible to generate ERCs. With 

respect to the federal plan, the EPA 

requests comment on the incorporation 

of non-affected WHP units. WHP units 

that meet the eligibility criteria under 

section VIII.K.1 of the Clean Power Plan 

preamble may be used to adjust the CO2

emission rate of an affected EGU. There 

are several types of WHP units. There 

are units, also referred to as bottoming 

cycle CHP units, where the fuel is first 

used to provide thermal energy for an 

industrial process and the waste heat 

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67 In such a configuration, the waste heat stream 

could also be generated from a mechanical process, 

such as at natural gas pipeline compressors. 68This only applies where no additional fossil 

fuel is used to supplement the use of waste heat in 

a WHP facility. Where fossil fuel is used to 

supplement waste heat in a WHP application, MWh 

of electrical generation that can be used to adjust 

the CO2 emission rate of an affected EGU must be 

prorated based on the proportion of fossil fuel heat 

input to total heat input that is used by the WHP 

unit to generate electricity. 

69This limitation prevents oversizing the thermal 

output of a WHP unit to exceed the useful 

industrial or other thermal load it is meeting, prior 

to generation of electricity. 

from that process is then used to 

generate electricity.67 There are also 

WHP units where the waste heat from 

the initial combustion process is used to 

generate additional power. Under both 

configurations, unless the WHP unit 

supplements waste heat with fossil fuel 

use, there is no additional fossil fuel 

used to generate this additional power. 

As a result, there are no incremental 

CO2 emissions associated with that 

additional power generation. As a 

result, the incremental electric 

generation output from the WHP units 

could be considered non-emitting, for 

the purposes of meeting the EGs, and 

the MWh of electrical output could be 

used to adjust the CO2 emission rate of 

an affected EGU.68 The MWh of 

electrical output from a WHP unit that 

can be recognized may not exceed the 

MWh of industrial or other thermal load 

that is being met by the WHP unit, prior 

to the generation of electricity.69 In 

addition, where fossil fuel is used to 

supplement waste heat in a WHP 

application, the EPA requests comment 

on what provisions to include in the 

final model rule to prorate the 

proportion of fossil fuel heat input to 

total heat input that is used by the WHP 

unit to generate electricity. The EPA 

also solicits comments on other 

potential accounting mechanisms for 

WHP. As noted above, the EPA requests 

comment incorporating WHP as an ERC 

generating resource for the federal plan. 

D. ERC Tracking and Compliance 

Operations 

The EPA proposes that the rate-based 

federal trading program use the agency’s 

already-existing Allowance Tracking 

and Compliance System (ATCS). Under 

the proposed rate-based trading 

program, the federal trading program 

would be maintained in the EPA’s 

existing data system. The ATCS would 

be used to track the trading of ERCs held 

by affected EGUs, as well as ERCs held 

by other entities. Specifically, the ATCS 

would track the generation of ERCs, 

holdings of ERCs in compliance 

accounts (i.e., accounts for affected 

EGUs) and general accounts (i.e., 

accounts for other entities and for 

affected EGUs, including affected EGUs 

that are under a ready-for-interstatetrading state plan), deduction of ERCs 

for compliance purposes, and transfers 

of ERCs between accounts. The primary 

role of the ATCS is to provide an 

efficient, automated means for covered 

sources to comply, and for the EPA to 

determine whether covered sources are 

complying with the emission rate 

standards. The ATCS would also 

provide data to the ERCs market and the 

public, including a record of ownership 

of ERCs, dates of ERC issuance, ERC 

transfers, buyer and seller information, 

serial numbers of ERCs transferred, 

emissions data, 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 would provide all 

required elements of a qualified ERC 

tracking system as described in section 

VIII of the final EGs. 

In the subsections that follow, the 

mechanisms by which a rate-based 

trading program would be implemented 

and administered are detailed. The EPA 

requests comment on each component 

of the trading system that is proposed in 

this preamble and the associated model 

rule, the trading program as a whole, 

and specifically requests comment on 

means to expedite the process of issuing 

ERCs, any minimum and maximum 

periods for which ERCs should be 

issued (e.g., monthly, quarterly, 

annually), and any means to ensure that 

the ERCs issued meet the requirements 

of the EGs and these proposed rules. 

The rate-based federal plan and model 

rule borrow many concepts from other 

successful trading programs, and the 

agency is interested in receiving 

additional information through 

comments on successful 

implementation of similar programs. 

1. Designated Representatives and 

Alternate Designated Representatives 

This section establishes the 

procedures for certifying and 

authorizing the designated 

representative, and alternate designated 

representative, of the owners and 

operators of the affected EGU and for 

changing the designated representative 

and alternate designated representative. 

These sections also describe the 

designated representative’s and 

alternate designated representative’s 

responsibilities and the process through 

which he or she could delegate to an 

agent the authority to make electronic 

submissions to the Administrator. These 

provisions would be patterned after the 

provisions concerning designated 

representatives and alternates in prior 

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 rate-based trading program. One 

alternate designated representative 

could be selected to act on behalf of, 

and legally bind, the designated 

representative and, thus, the owners and 

operators. Because the actions of the 

designated representative and alternate 

would legally bind the owners and 

operators, the designated representative 

and alternate would have to submit a 

certificate of representation certifying 

that each was selected by an agreement 

binding on all such owners and 

operators and was authorized to act on 

their behalf. 

The designated representative and 

alternate would be authorized upon 

receipt by the Administrator of the 

certificate of representation. This 

document, in a format prescribed by the 

Administrator, would include: Specified 

identifying information for the covered 

source and covered EGUs at the source 

and for the designated representative 

and alternate; the name of every owner 

and operator of the affected EGU; and 

certification language and signatures of 

the designated representative and 

alternate. All submissions (e.g., 

monitoring plans, monitoring system 

certifications, and allowance transfers) 

for an affected EGU would have to be 

submitted, signed, and certified by the 

designated representative or alternate. 

Further, upon receipt of a complete 

certificate of representation, the 

Administrator would establish a 

compliance account in the ATCS for the 

affected EGU involved. 

In order to change the designated 

representative or alternate, a new 

certificate of representation would have 

to be received by the Administrator. A 

new certificate of representation would 

also have to be submitted to reflect 

changes in the owners and operators of 

the affected EGU involved. However, 

new owners and operators would be 

bound by the existing certificate of 

representation even in the absence of 

such a submission. 

In addition to the flexibility provided 

by allowing an alternate to act for the 

designated representative (e.g., in 

circumstances where the designated 

representative might be unavailable), 

additional flexibility would be provided 

by allowing the designated 

representative and alternate to delegate 

authority to make electronic 

submissions on his or her behalf. The 

designated representative and alternate 

could designate agents to submit 

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70 ‘‘Compliance true-up’’ refers to ERC 

submission by an owner or operator of an affected 

EGU to adjust a reported CO2 emission rate, and 

determination of whether the adjusted rate is equal 

to or lower than the applicable rate-based emission 

limit. 

71Note that affected EGUs will submit these 

values to the EPA and the values will go through 

a transparent review process. 

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 ratebased trading program. 

2. ERC Tracking and Compliance 

System 

The rate-based trading program rules 

establish the procedures and 

requirements for using and operating 

the ATCS (which is the electronic data 

system through which the 

Administrator would handle ERC 

issuance, holding, transfer, and 

deduction), and for determining 

compliance with the ERC-holding 

requirements in an efficient and 

transparent manner. The ATCS provides 

a record of ownership, dates of ERC 

transfers, buyer and seller information, 

origin of ERCs, the serial numbers of 

ERCs transferred, and ERC type (i.e., if 

it is a GS–ERC or not). ERC price 

information would not be included in 

the ATCS. The EPA’s experience is that 

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

better position to obtain and 

disseminate timely, accurate price 

information than the EPA. For example, 

because not all ERC transfers are 

immediately reported to the 

Administrator, the Administrator would 

not be able to ensure that any reported 

price information associated with the 

transfers would reflect current market 

prices. 

3. Tracking System Requirements 

This federal plan and model rule’s 

proposed tracking system and tracking 

systems that will be presumptively 

approvable for state plans fufill the 

criteria set forth in the final EGs. The 

EPA’s tracking system includes 

provisions to ensure that ERCs issued to 

any eligible entity are properly tracked 

from issuance to submission by affected 

EGUs for compliance (where ERCs are 

‘‘surrendered’’ by the owner or operator 

of an affected EGU and ‘‘retired’’ or 

‘‘cancelled’’ by the Administrator or 

administering state regulatory body), to 

ensure they are used only once to meet 

a regulatory obligation. This is 

addressed through specified 

requirements for tracking system 

account holders, ERC issuance, ERC 

transfers among accounts, compliance 

true-up for affected EGUs,70 and an 

accompanying tracking system 

infrastructure design. Each issued ERC 

will have a unique identifier (i.e., serial 

number) and the tracking system will 

provide traceability of issued ERCs back 

to the program or project for which they 

were issued. 

The EPA received a number of 

comments from states and stakeholders 

on the Clean Power Plan about the value 

of the EPA’s support in developing and/ 

or administering tracking systems to 

support state administration of ratebased emission trading systems. As 

described above in section III.A of this 

preamble, the EPA is proposing, as part 

of both types of model trading rules, a 

federal trading platform that would 

allow state plans that are ready-forinterstate-trading to operate through a 

program in which the EPA provides the 

tracking and compliance system. This 

system will meet the requirements of 

the Clean Power Plan. 

4. Compliance and General Accounts 

This section describes two types of 

ATCS accounts: Compliance accounts, 

which would be established by the 

Administrator for each affected EGU 

upon receipt of the certificate of 

representation for the source; and 

general accounts, which could be 

established by any entity upon receipt 

by the Administrator of an application 

for a general account. A compliance 

account would be the account in which 

any ERCs used by the affected EGU for 

compliance with the emissions 

limitations would have to be held until 

retired for compliance. 

General accounts could be used by 

any person or group for holding or 

trading ERCs. However, ERCs could not 

be used for compliance with emissions 

limitations so long as the ERCs were 

held in, and not properly and timely 

transferred out of, a general account. To 

open a general account, a person or 

group would be required to submit an 

application for a general account, which 

would be similar in many ways to a 

certificate of representation. The 

application would include, in a format 

to be prescribed by the Administrator: 

The name and identifying information 

of the individual who would be the 

authorized account representative and 

of any individual who would be the 

alternate authorized account 

representative; an identifying name for 

the account; the names of all persons 

with an ownership interest with the 

respect to allowances held in the 

account; and certification language and 

signatures of the authorized account 

representative and alternate. The 

authorized account representative and 

alternate would be authorized upon 

receipt of the application by the 

Administrator. The provisions for 

changing the authorized account 

representative and alternate, for 

changing the application to take account 

of changes in the persons having an 

ownership interest with respect to ERCs, 

and for delegating authority to make 

electronic submissions would be 

analogous to those applicable to 

comparable matters for designated 

representatives and alternates. The EPA 

requests comment on these compliance 

mechanisms. 

5. Compliance Demonstration 

The EPA proposes that affected EGUs 

subject to this federal plan are required 

to meet compliance obligations by 

November 1 of the year following the 

end of the compliance period. For an 

affected EGU to meet its compliance 

obligations its average stack emission 

rate over the compliance period must be 

at or below its applicable rate standard, 

or the affected EGU must use ERCs to 

adjust its average stack emission rate to 

be at or below its applicable rate 

standard. An EGU’s average emission 

rate over the compliance period will be 

calculated based on submitted data to 

ATCS. The compliance period average 

would be calculated by taking the 

measured CO2 mass in units of pounds 

(lbs) summed over the compliance 

period for an affected EGU and dividing 

it by the total net energy output over the 

compliance period for that affected EGU 

in units of MWh.71 This averaged 

emission rate will be compared to the 

emissions standards that the affected 

EGU is subject to during the 

corresponding compliance period. 

Accordingly, and if necessary, the 

appropriate number of ERCs will be 

retired from the affected EGU’s 

compliance account to adjust the 

emission rate of the affected EGU to be 

equal to the emission standard. The 

discussion of using ERCs for compliance 

is found in section IV.D.10 of this 

preamble. 

6. Recordation of ERC Generation and 

ERC Issuance 

The EPA proposes to issue ERCs for 

ERC generating entities once per year. 

Thus, in a 3-year compliance period, for 

instance, there would be three points at 

which the agency issues ERCs. After 

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72As described in section IV.C.1 of this preamble. 

each calendar year, the EPA would 

calculate the ERCs generated for affected 

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 would 

be proposed as part of a Notice of Data 

Availability (NODA) with a 30-day 

comment period. Subsequently, the EPA 

would finalize this NODA and issue 

ERCs in accordance with the NODA, 

with tracking and serial numbers. For 

affected EGUs with compliance 

accounts, the ERCs would be issued to 

these. For entities without compliance 

accounts, the EPA would issue ERCs to 

an entity’s general account. The timing 

for issuing ERCs would be 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 ERC-issuance 

intervals. We request comment on how 

reporting and recordkeeping 

requirements could be minimized, 

particularly for small entities, to the 

extent possible under the statute and 

existing regulations. 

a. Issuance of ERCs to Affected EGUs. 

Following the determination of the 

number of ERCs an affected EGU is 

eligible to receive, based on an affected 

EGU’s reported CO2 emission rate 

compared to a specified reference rate,72

the EPA will issue those ERCs into the 

affected EGU’s compliance account in 

ATCS. The issuance will occur annually 

through the NODA process. ERCs will 

have a unique serial number, tracking 

number, and will distinguish ERC type 

(i.e., if it is BB2 or not) when issued to 

an affected EGU. 

b. Issuance of ERCs for Measures 

Used to Adjust an Emission Rate. In the 

final EGs, the EPA has specified 

requirements for an ERC issuance 

process for the quantification and 

verification of measures used to adjust 

an emission rate that provide the 

necessary rigor and transparency while 

being efficient and streamlined. This is 

the intent of the federal plan as well, 

where there is a particular concern with 

implementing a streamlined and 

efficient federal process for ERC 

issuance across federal plan states. As 

required in the final EGs, we are 

proposing a two-step application 

process to the federal plan tracking 

systems for ERCs that allows for project 

approval to take place prior to the 

performance period, and makes the 

issuance of ERCs as quick and efficient 

as possible after generation has been 

quantified and verified, while still 

assuring a rigorous approval process. 

For the first step in the ERC issuance 

application process, the EPA proposes 

that RE and nuclear generation 

providers submit to the EPA or its 

designated agent an eligibility 

application for EPA approval, 

demonstrating that the project is eligible 

for the issuance of credits, including an 

EM&V plan that meets EPA 

requirements. The EPA requests 

comment on all aspects of the proposed 

ERC issuance process. The EPA also 

requests comment on how an ERC 

issuance process would apply to 

emission reduction measures for which 

we are requesting 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, WHP, biomass, 

and any other measure that could be 

considered eligible under the final 

guidelines. 

The following are proposed required 

components of the eligibility 

application, as specified for these 

measures in the final EGs: 

(1) The EPA proposes that the federal plan 

will require that providers must show that 

the generation they would be providing to 

the federal plan system for ERC issuance is 

only being credited in the federal plan, and 

will not be submitted for ERC issuance in any 

other rate-based crediting system in any other 

state. As discussed in section IV.C. of this 

preamble, we are proposing that states with 

rate-based emission standards plans that 

have eligibility and EM&V requirements 

compatible with the federal plan would have 

the opportunity to participate in the federal 

plan trading systems, and create a shared 

pool of creditable reductions, in which case 

credits approved by such states would be 

eligible for use by affected EGUs in the 

federal plan. 

(2) The provider must show that the project 

is using an eligible RE or nuclear resource. 

Specific requirements are proposed in 

section IV.C of this preamble. 

(3) The provider must show that the project 

has an EM&V plan that meets the federal plan 

requirements. Proposed requirements 

specific to the federal plan are proposed in 

section IV.D.8 of this preamble. As specified 

in section IV.D.8 of this preamble, we request 

comment on whether nuclear energy 

resources should be subject to the same 

EM&V requirements as RE resources, and if 

not, we request comment on the EM&V 

requirements to which nuclear energy 

resources should be subject. 

(4) There are special conditions if the 

provider is located in a state with a massbased plan. 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 generation 

was produced to meet electricity load in a 

state with a rate-based plan. The EPA is 

proposing that an RE provider can make this 

demonstration by providing documentation 

of a power purchase agreement or delivery 

contract from the rate-based state and show 

that the measure was treated as a generation 

resource used to serve regional load that 

included the rate-based state. For 

incremental nuclear capacity, no provider in 

a state with a mass-based plan can be eligible 

for ERC issuance in a rate-based state. This 

requirement and the justification for its 

inclusion is further discussed in section III.A 

of this preamble on Interstate Effects and also 

discussed in the Interstate Effects section of 

the final EGs (see sections VIII.K.1 and 

VIII.L). The EPA is proposing that there 

would be no other geographic limitation on 

the location of the providers of RE and 

incremental nuclear generation submitted for 

ERC issuance under the rate-based federal 

plan approach. 

(5) This application must include an 

independent third-party verifier’s review and 

approval of the eligibility requirements, as is 

reflected in EM&V requirements for the final 

guidelines, and specified as part of the 

proposed federal plan EM&V requirements in 

section IV.D.8 of this preamble. 

We request comment on each 

criterion of the eligibility application 

described herein and in the proposed 

model rule, for each eligible resource. 

Specifically, we seek comment on the 

substantive content of the criteria, and 

we seek comment on the level of detail 

provided and whether more or less 

detail (and what detail) should be 

included in the final model rule. 

The EPA is proposing that ERCs 

would be tracked in the ATCS. 

Additionally, the EPA is proposing that 

the agency would establish a 

complementary tracking system for the 

ERC issuance process. It would provide 

for transparent access to RE project and 

program eligibility applications and 

regulatory approvals as well as 

information on the activities of 

accredited third party verifiers (third 

party verifiers are further discussed in 

section IV.D.7 of this preamble), as well 

for the public to be able to generate 

reports based on this information. 

The agency is proposing that the 

project eligibility applications would 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 would be accepted on an 

annual basis. The agency requests 

comment on whether a quarterly or 

biannual application process is more 

appropriate. These applications would 

be accepted through the entirety of all 

compliance periods. The EPA will 

review and approve the project 

applications. It is proposed that the EPA 

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73As discussed in section VIII.B.2 of the final 

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

plan including requirements for the state’s 

participation in the CEIP, eligible RE projects may 

commence construction, and eligible EE projects 

may commence implementation, following the date 

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

projects must be implemented in or benefit the state 

that submitted the final state plan to the EPA, and 

may receive incentives for the zero-emitting MWh 

they generate or the end-use energy savings they 

achieve during 2020 and/or 2021. 

may designate an agent to coordinate 

the project application process and 

assist with review of applications. 

For the second step in the credit 

issuance application process, the EPA 

proposes that providers submit an M&V 

report to the EPA, or its designated 

agent, prior to the EPA’s issuance of 

ERCs. This can only occur after the 

approval of a project application, the RE 

has been generated, and necessary 

EM&V has been completed. 

The following are proposed required 

components of the M&V Report: 

(1) Documentation of completed EM&V in 

accordance with the EM&V plan submitted 

by the RE or nuclear provider, including 

quantification of the MWh of generation to be 

credited and verification of their creation. 

(2) Documentation that the generation has 

not been submitted for crediting under any 

other federal or state plan, including to 

another rate-based credit tracking system. 

(3) Documentation that the MWh resulted 

from RE or incremental nuclear capacity 

eligible for crediting under the federal plan 

requirements and in accordance with final 

EGs. This documentation should note if the 

MWh are from an RE project located in a 

state with a mass-based plan, and show if the 

generation is approved to be eligible for ERC 

issuance under the federal plan. See above 

geographic eligibility discussion and section 

III.A of this preamble for specifics on the 

required demonstration for this type of RE 

generation. As discussed in that section, this 

option is proposed to not be available to 

incremental nuclear capacity located in a 

state with a mass-based plan. 

(4) This application must include a 

verification report from an independent 

third-party verifier, submitted after the 

verifier’s review and approval of the 

eligibility application, as is reflected in 

EM&V requirements for the final guidelines, 

and specified as part of proposed federal plan 

EM&V requirements described below and 

included in detail in the proposed model 

rule. 

If the application meets these 

requirements, pursuant to review by the 

EPA or its designated agent, ERCs will 

be issued to the provider by the EPA 

through the 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 

described in the proposed model rule. 

One of the steps requires the proponent 

to register for a general account in the 

EPA tracking system where the ERCs 

would be recorded. See 40 CFR 

62.16515 for the requirements to 

establish a general account. While EPA 

is proposing to allow eligible resources 

to use a general account to receive any 

ERCs issued under this section, the EPA 

requests comment on extending the 

designated representative provisions in 

40 CFR 62.16485 to eligible resources 

instead of the general account 

provisions. Requiring eligible resources 

to submit information similar to that 

collected in the certificate of 

representation in 40 CFR 62.16500 and 

to appoint a designated representative to 

act on behalf of all owners/operators for 

all projects requesting ERCs may 

improve the EM&V process by making 

the eligible resources more accountable. 

Because it is critical to the integrity of 

an ERC that it represents the actual 

MWh of energy generated or saved that 

it purports to represent, and as required 

in the EGs for state plans, the federal 

plan and model rule include provisions 

to address error correction (i.e., 

mechanisms to adjust the number of 

ERCs issued based on all form of errors, 

e.g., clerical errors, over- and understatements, material inconsistency with 

rule provisions, fraud, etc.). In addition, 

the federal plan and model rule include 

provisions that provide that, at any time 

for cause, the EPA may temporarily or 

permanently revoke the qualification 

status of eligible resources from being 

issued ERCs for at least the duration it 

does not meet the requirements for 

being issued ERCs and independent 

verifiers from providing verification 

services for at least the duration it does 

not meet the requirements of the state 

plan. For the federal plan, as discussed 

in section III.I of this preamble above, 

we propose to use the administrative 

appeals process set forth 40 CFR part 78 

to address party-specific disputes 

concerning the issuance 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 M&V 

reports will be accepted starting before 

the beginning of the first compliance 

period (January 1, 2022), through an 

application process the agency will 

establish and administer, and that 

applications will be accepted on an 

annual basis. These applications will be 

accepted through the entirety of all 

compliance periods. The EPA will 

review and approve M&V reports, and 

may designate an agent to coordinate 

and assist with M&V reports. The EPA 

is proposing that it will issue ERCs for 

a given year no later than 6 months after 

the end of the relevant year. This 

amount of time may be necessary to 

accommodate the ERC issuance process, 

including necessary EM&V. The overall 

proposed schedule for trading and trueup has been constructed to allow for 

this period of time for EM&V after the 

compliance period. 

For purposes of the proposed ratebased federal plan, the EPA proposes to 

implement the CEIP on behalf of a state 

by issuing early action ERCs for eligible 

actions located in or benefitting that 

state that are implemented after 

September 6, 2018 and that generate 

zero-emitting MWh or reduce energy 

demand in 2020 and/or 2021.73 The 

EPA intends to implement the program 

in a way that maintains the stringency 

of the rate-based emission standards for 

affected EGUs in the compliance 

periods established in this rule. For the 

purposes of the rate-based federal plan, 

the EPA is proposing to award early 

action ERCs to two types of eligible 

projects, as listed below. The rationale 

for including these projects is included 

in section VIII.B.2 of the final EGs. 

• RE investments that generate 

metered MWh from any type of wind or 

solar resources; and 

• Demand-side EE programs and 

measures implemented in low-income 

communities that result in quantified 

and verified electricity savings (MWh). 

The EPA proposes the following 

framework to implement the CEIP in the 

rate-based federal plan. First, the EPA 

proposes to implement a mechanism for 

issuing early action ERCs for eligible RE 

projects that commence construction 

and eligeible EE projects that commence 

implementation after September 6, 2018 

and that generate zero-emitting MWh or 

reduce end-use energy demand during 

2020 and/or 2021. These projects must 

be located in or benefit the state on 

whose behalf the EPA is implementing 

the federal plan. The EPA proposes to 

design this mechanism in a manner that 

would have no impact on the aggregate 

emission performance of sources 

required to meet rate-based emission 

standards during the compliance 

periods. The EPA requests comment on 

the structure of this mechanism, which 

could include adjusting the stringency 

of the emission standards during the 

compliance periods to account for the 

issuance of early action ERCs for MWh 

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74 In this section, the term ‘‘verifier’’ is used 

interchangeably to refer to both a ‘‘verification 

body’’ (i.e., a verification company or organization) 

and a ‘‘verifier,’’ which is an individual that is a 

principal or employee of a verification body. 

75Accredited verification bodies and individual 

verifiers may not have any direct or indirect 

organizational or personal relationships with an 

ERC provider that would impact their impartiality 

in assessing the validity and accuracy of the 

information in an eligibility application or M&V 

report. In addition to this general requirement, the 

following specific requirements also apply. 

Accredited verifiers must have no direct or indirect 

financial interest in, or other financial relationships 

with, an ERC provider or any related program or 

project that seeks issuance of ERCs. Accredited 

verifiers must have no relationship with the 

implementer of a program or project that seeks the 

issuance of ERCs, or any related ERC provider, that 

would represent a COI. Accredited verifiers must 

have no role in the development and 

implementation of a program or project that seeks 

issuance of ERCs, beyond the provision of 

verification services. Accredited verifiers must not 

be compensated, directly or indirectly, in relation 

to the quantified and verified MWh in an M&V 

report or on the basis of program or project 

approval, ERC issuance, or the number of ERCs 

issued. Accredited verifiers may not hold ERCs, or 

other financial derivatives related to ERCs, or have 

a financial relationship with other parties that hold 

ERCs or other related financial derivatives. 

Verification reports must include an attestation by 

the accredited verifier that it assessed potential COI 

related to an ERC provider and adequately 

addressed any identified COI. The EPA requests 

comment the potential for payments to be 

channeled through the EPA as fees. 

generated or avoided in 2020 and/or 

2021. For example, during the interim 

performance period, a number of ERCs 

could be retired in an amount 

equivalent to the number of early action 

ERCs that were awarded for MWh 

generated or avoided in 2020 and/or 

2021. As another option, the EPA, or a 

state under the model trading rule, 

could adjust their targets to achieve the 

same stringency, taking into account the 

additional borrowed ERCs. The EPA 

requests comments on all potential 

methods to adjust state targets, 

including modeling-based approaches, 

and on what information the state must 

present to demonstrate that the new 

targets preserve the needed stringency. 

More generally, the EPA requests 

comments on these ideas, as well as on 

alternatives for maintaining the 

stringency of a rate-based plan 

implementing the CEIP so as to have no 

impact on the aggregate emission 

performance of sources required to meet 

rate-based emission standards during 

the compliance periods. 

Second, the agency proposes to create 

an account of ‘‘matching’’ ERCs for each 

state participating in the CEIP— 

regardless of whether a state is 

implementing a state plan or the agency 

is implementing a federal plan on its 

behalf. This distribution would reflect 

each state’s pro rata share—based on the 

amount of the reductions from 2012 

levels the affected EGUs in the state are 

required to achieve relative to those in 

the other participating states—of a 

federal pool of additional ERCs, which 

would be limited to the equivalent of 

300 million short tons of CO2 emissions. 

Thus, states whose affected EGUs have 

greater reduction obligations will be 

eligible to secure a larger proportion of 

the federal pool upon demonstration of 

quantified and verified MWh of RE 

generation or demand side-EE savings 

from eligible projects realized in 2020 

and/or 2021. The EPA intends that a 

portion of these matching ERCs would 

be reserved for eligible wind and solar 

projects, and a portion would be 

reserved for eligible EE projects 

implemented in low-income 

communities. The agency recognizes 

that there have been historical 

economic, logistical and information 

barriers to implementing EE programs in 

these communities, and therefore 

believes it is appropriate to reserve a 

portion of the federal pool to incentivize 

investment in these programs. The EPA 

requests comment on the size of reserve 

of matching ERCs for eligible lowincome EE programs as well as for 

eligible wind and solar projects. The 

EPA is proposing that unused ERCs in 

either reserve would be redistributed 

among participating states. This 

redistribution could be executed 

according to the pro rata method 

discussed above. Alternatively, unused 

matching EE or RE ERCs could be swept 

back into a federal pool and distributed 

to project providers on a first-come, first 

served basis. EPA requests comment on 

these ideas as well as alternative 

proposals regarding the method for 

redistributing matching ERCs, as well as 

the appropriate timing for such a 

redistribution. 

Following the effective date of a ratebased federal plan for a state, the agency 

will create an account of matching ERCs 

for the state that reflects the pro rata 

share of the 300 million short ton CO2

emissions-equivalent matching poolthat 

the state is eligible to receive. Any 

matching ERCs that remain 

undistributed after September 6, 2018 

will be distributed to those states with 

approved state plans that include 

requirements for CEIP participation, as 

well as to those states on whose behalf 

EPA is implementing a federal plan. 

These ERCs will be distributed 

according to the pro rata method 

outlined above. Unused matching ERCs 

that remain in the accounts of states 

participating in the CEIP on January 1, 

2023, will be retired by the EPA. 

7. Independent Verifiers 

The EPA has determined in the final 

EGs that independent verification 

requirements are necessary to ensure the 

integrity of any rate-based emission 

trading program, given the types of 

eligible measures that may generate 

ERCs and the broad geographic 

locations in which those measures may 

occur. Inclusion of an independent 

verification component provides 

technical support for the EPA in the 

context of the proposed federal plan, 

and the states in the context of their 

plans, to ensure that eligibility 

applications and monitoring and 

verification reports are appropriately 

reviewed prior to issuance of ERCs. 

Inclusion of an independent verification 

component is also consistent with 

similar approaches required by state 

PUCs for the review of demand-side EE 

program results and GHG offset 

provisions included in state GHG 

emission budget trading programs. 

The remainder of this section and the 

related language in the proposed model 

rule provide the proposed basis by 

which the EPA intends to evaluate the 

independence of the verifiers that it 

uses to provide verification reports 

pursuant to the federal plan. The 

qualifications described here and in the 

model rule would be presumptively 

approveable in the context of a state 

plan. 

As a starting point, an independent 

verifier must have the necessary 

technical qualifications to provide 

verification services for the subject in 

question, as well as fulfill certain codes 

of conduct in providing verification 

services. Only verifiers approved or 

‘‘accredited’’ by the EPA may provide 

verification services related to ERC 

issuance for the federal plan, in the 

same way that only verifiers approved 

by a state may be eligible to perform 

verification services pursuant to a state 

plan.74

In addition, verifiers must have 

sufficient knowledge of the rate-based 

emission trading program rules, 

technical expertise, and knowledge of 

auditing, accounting, and information 

management practices, in order to 

perform verifcation services related to 

the Clean Power Plan. Accredited 

verifiers must be independent. 

Accredited verifiers may not provide 

verification services for any eligible 

resource for which they have a 

financial, management, or other 

interest.75 Such relationships constitute 

a conflict of interest (COI). COI 

situations may also arise as a result of 

personal relationships among 

individuals representing an ERC 

provider and an accredited verifier. A 

verification report would not be 

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76An example is American National Standards 

Institute (ANSI) accreditation under ISO 

14065:2013 for GHG validation and verification 

bodies. More information is available at https://

www.ansica.org/wwwversion2/outside/

GHGgeneral.asp. 77EM&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 to ensure that the resulting 

savings and generation are quantifiable and 

verifiable. In this proposal, we are proposing EM&V 

for the eligible RE, and we request comment on 

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

that could be eligible. 

78The 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. 

79A full discussion of applicable requirements for 

the establishment and functioning of the rate-based 

trading system is provided above, in section IV.D 

of this preamble. 

80See discussion beginning on p. 34 of the State 

Plan Considerations TSD for the Clean Power Plan 

Proposed Rule: http://www2.epa.gov/carbonpollution-standards/clean-power-plan-proposedrule-state-plan-considerations. 

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. 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 

would perform periodic reviews of 

accredited verifiers, to ensure that 

verifiers are maintaining necessary 

technical and professional qualifications 

and are meeting program requirements 

for provision of verification services. 

The EPA may recognize, in part, 

accreditation by an outside organization 

where such outside accreditation 

demonstrates that federal plan 

requirements are met.76 The EPA 

requests comment on the proposed 

necessary requirements for an 

independent verifier to perform 

verification services in connection with 

the federal plan, including those 

requirements specifically detailed in 

this section of the preamble and the 

related language in the proposed model 

rule, and including whether there are 

any requirements that are not included 

in this proposal that should be included 

in the final rule. We further request 

comment on the level of detail that we 

should include in the final model rule 

regarding all requirements for 

indepenent verifiers, and all aspects of 

verification. 

8. Evaluation, Measurement, and 

Verification Plans, Monitoring and 

Verification Reports, and Verification 

Reports 

This section identifies and discusses 

the EM&V approaches used to quantify 

and verify MWh from RE, demand-side 

EE, and other eligible measures used to 

generate ERCs or otherwise adjust an 

emission rate.77

Only a subset of the potentially 

creditable ERC resources 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: Onshore wind, solar, geothermal power, 

hydropower, or new nuclear units and 

capacity uprates at existing nuclear 

units; and (2) they can provide 

quantified generation data from a 

revenue quality meter. The language 

pertaining to all other measures (e.g., 

demand-side EE) is proposed only for 

the model rule. While they are currently 

being proposed as part of the model rule 

and not the federal plan, the EPA 

requests comment on the inclusion of 

other RE measures, demand-side EE 

measures, and any other measures that 

may be eligible under the final 

guidelines as eligible measures under 

the federal plan. For stakeholders that 

are submitting comments on the 

inclusion of such additional measures, 

the EPA requests comment on how the 

EPA could implement across applicable 

jurisdictions a rigorous, straightforward, 

and widely demonstrated set of EM&V 

methods, procedures, and approaches 

that could be implemented in the time 

frame allowed by the federal plan and 

that also meet the requirements outlined 

in the final guidelines. To the extent 

they are proposed for inclusion in the 

model trading rule, we also invite 

comment on these requirements in the 

context of state implementation as part 

of a state plan. Thus, commenters on 

this aspect of the proposal should 

consider whether and how these 

provisions could be implemented at the 

state level. Comments that suggest an 

approach not authorized by the EGs will 

likely be considered outside the scope 

of this proposed rule. 

Additionally, with respect to EM&V, 

the EPA describes certain established 

industry best-practice methods, 

procedures, and approaches that would 

be presumptively approvable if 

included in state plans. States wishing 

to adopt the model rule must submit 

these methods, procedures, and 

approaches as specified, or may submit 

alternative EM&V that is functionally 

equivalent to the industry best-practices 

described as presumptively 

approvable.78

As discussed in section IV.C.3 of this 

preamble, quantified and verified MWh 

of RE generation and other means of 

generating ERCs may be used to adjust 

a CO2 emission rate when 

demonstrating compliance with the EGs. 

Providers other than affected EGUs who 

seek to earn ERCs must develop EM&V 

plans outlining how they will quantify 

and verify the resulting MWh from their 

efforts. These providers must then 

submit these EM&V plans as part of 

their application to the Administrator 

for project approval.79

a. Overall Approach and MeasureSpecific Requirements. The proposed 

Clean Power Plan stated that the EPA 

would establish EM&V requirements 

and procedures to help states, sources, 

and resource providers quantify and 

verify MWh savings and generation 

resulting from zero-emitting RE and 

demand-side EE efforts. This action 

proposes those requirements that the 

EPA committed to establish. The Clean 

Power Plan proposal and associated 

‘‘State Plans Considerations’’ TSD 80

suggested that such EM&V requirements 

would leverage existing industry 

practices, protocols, and tracking 

mechanisms currently utilized by the 

majority of states implementing RE and 

demand-side EE. The EPA further noted 

that many state regulatory bodies and 

other entities already have significant 

EM&V infrastructure in place and have 

been applying, refining, and enhancing 

their evaluation and quality assurance 

approaches for over 30 years, 

particularly with regard to the 

quantification and verification of energy 

savings resulting from utilityadministered 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 bestpractices. 

In addition, the EPA’s proposed 

EM&V methods, procedures, and 

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approaches reflect several overarching 

objectives and principles offered by 

states, private organizations, and the 

public during the comment period of 

the Clean Power Plan EGs. One of these 

is the importance of balancing the 

accuracy and reliability of results with 

the associated costs of EM&V. Another 

objective for the EPA’s proposed EM&V 

is to avoid excessive interference with 

existing practices that are already 

robust, transparent and effective. 

Submittals. Applicable submittals 

under a rate-based emission trading 

program include eligibility applications 

(including EM&V plans), monitoring 

and verification reports, and verification 

reports. These submittals are described 

in section VIII.K.3.b of the final EGs 

preamble and in this model rule and 

federal plan. At the initiation of a 

program or project, ERC providers 

develop and submit to the state or the 

EPA, respectively, an EM&V plan that 

documents how requirements for 

quantification and verification will be 

addressed as EM&V is performed over 

the program or project period. After 

implementation has occurred, the ERC 

provider must submit periodic 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 

request broad comment on each criteria 

specified below and in the proposed 

model rule, for each eligible resource. 

Specifically, we seek comment on the 

substantive content of the criteria, and 

we seek comment on the level of detail 

provided and whether more or less 

detail (and what detail) should be 

included in the final model rule, and 

whether the criteria should differ for 

each eligible resource. 

Each M&V report submitted in 

support of the issuance of ERCs to a 

specific eligible resource must include 

specific criteria described here and in 

the proposed model rule. For the first 

M&V report submitted, a key component 

is documentation that the electricitygenerating resources or electricitysaving 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 quantity (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 

requests broad comment on each of 

these criteria, as described here and in 

the proposed model rule. Specifically, 

we seek comment on the substantive 

content of the criteria, and we seek 

comment on the level of detail provided 

and whether more or less detail (and 

what detail) should be included in the 

final model rule, and whether the 

criteria should differ for each eligible 

resource. 

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 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 are 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 requests 

broad comment on each of these criteria, 

as described here and in the proposed 

model rule. Specifically, we seek 

comment on the substantive content of 

the criteria, and we seek comment on 

the level of detail provided and whether 

more or less detail (and what detail) 

should be included in the final model 

rule, and whether the criteria should 

differ for each eligible resource. 

For demand-side EE, all EM&V plans 

that are developed for purposes of 

adjusting an emission rate under this 

proposed rule are intended to leverage 

and closely resemble the plans already 

in routine use for a wide range of 

publicly or rate-payer funded EE 

programs and energy service company 

(ESCO) projects. For RE, EM&V plans 

similarly leverage resources and 

approaches to MWh tracking for RE that 

are broadly applied in the state and 

regions. The existing reports and 

documentation from existing tracking 

systems may serve as the substantive 

basis for a monitoring and verification 

report for RE. 

b. Renewable Energy EM&V 

Requirements. This section describes 

the EM&V requirements associated with 

quantifying electricity generation from 

eligible RE and nuclear energy, and for 

documenting these requirements in 

EM&V plans and reports. Consistent 

with prevailing views expressed in 

public comments, the EPA’s 

requirements presume that the 

quantification of RE generation can 

leverage the infrastructure and 

documentation associated with the 

establishment of renewable energy 

certificates (RECs) and registration of 

such certificates in REC registries. These 

registries typically include 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. 

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The primary metric for all RE is 

electricity generation, in units of MWh. 

Measured output must be derived either 

from: (1) A revenue quality meter that 

meets the applicable ANSI C–12 

standard or equivalent, which is the 

typical requirement for settlements with 

RTO and other control-area operators; or 

(2) For customer-sited generators that 

are interconnected behind the customer 

meter, measurement at the AC output of 

an inverter, adjusted to reflect the 

energy delivered into either the 

transmission or distribution grid at the 

generator bus bar. Further, a RE 

generating facility of 10 Kilowatt 

capacity or less may estimate the 

facility’s output if the state where it is 

located explicitly allows estimates to be 

used and provides rules for when it will 

be allowed. In the latter case, 

calculations of system output must be 

based on the RE unit’s capacity, 

estimated capacity factors, and an 

assessment of the local conditions that 

affect generation levels. All such input 

parameters and assumptions must be 

clearly described and documented. For 

RE units that are managed by regional 

transmission operators or other control 

area operators, metered generation data 

should be electronically collected by the 

control area’s energy management 

system, verified through an energy 

accounting or settlements process, and 

reported by the control area operator to 

the REC registry at least monthly. The 

EPA requests comment on this proposed 

requirement for quantifying RE 

generation for the purpose of ERC 

issuance. 

For RE units that do not go through 

a control area settlements process, 

metered data may be read and 

transmitted to the ERC registry by an 

independent third party, or may be selfreported. Third-party and self-reported 

generation data must be reported on an 

annual basis. All such data must be 

verified for reasonableness by the 

agency, the state, or the REC registry. 

For reporting purposes, RE generation 

may be aggregated from multiple 

generators into a single MWh value for 

the group, provided the following 

requirements are met: Each RE unit is 

uniquely identified in the federal 

tracking system, the nameplate capacity 

of each RE unit is less than 150 

Kilowatt, the aggregated RE units 

collectively have nameplate generating 

capacities less than 1.0 MW, the units 

aggregated are located in the same state, 

the RE units being aggregated utilize the 

same technology/fuel type, and the RE 

unit’s generation data are based on the 

same metering or the same generation 

estimating software or algorithms. The 

EPA requests comment on how existing 

reporting systems can play a role in 

meeting EM&V requirements under the 

federal plan and model rule, 

particularly, in assuring that each MWh 

of RE generation is uniquely identified 

and recorded to avoid double counting. 

An additional consideration regarding 

distributed RE units that directly serve 

on-site end-use electricity loads is that 

avoided transmission and distribution 

(T&D) system losses can be quantified, 

as is commonly practiced with demandside EE. If such T&D losses are 

quantified, the requirements for 

demand-side EE would be applicable. 

The EPA requests comment on all 

metering, measurement, verification, 

and other requirements proposed in this 

subsection, including the 

appropriateness of their use for each 

type of RE resource (including the 

relevant size and distribution of such 

resource) that qualifies for issuance of 

ERCs for use for compliance. 

For RE resources with a nameplate 

capacity of 10 Kilowatt or more and for 

RE resources with a nameplate capacity 

of less than 10 Kilowatt for which 

metered data are available, we request 

comment on the appropriateness of the 

requirement to use a revenue quality 

meter for monitoring generation, and we 

request comment on the definition of 

revenue quality meter. We request 

comment on the appropriateness of 

other types of meters for monitoring 

generation. We request comment on 

whether 10 Kilowatt is the appropriate 

threshold, under which an eligible 

resource can be issued ERCs for 

generation based on data other than 

metered generation, and if not, what 

would be the appropriate threshold. 

For RE resources of all sizes and 

means of monitoring, we request 

comment on the appropriate 

requirements for allowing generation 

data to be aggregated, including 

comment on the provisions in the 

proposed model rule and any 

alternatives to them. We request 

comment on whether all of the 

generating units have the same essential 

generation characteristics, in order for 

their data to be aggregated, and if so, 

what is the appropriate definition of 

‘‘essential generation characteristics’’ 

(e.g., are essential generating 

characteristics determined on a resource 

by resource basis, or can generation 

from a group of wind turbines be 

aggregated with generation from a group 

of solar panels?) We seek comment on 

the appropriate thresholds for the 

aggregated of individual units (e.g., 

nameplate capacity of less than 150 

Kilowatt per unit and the units 

collectively do not exceed a total 

nameplate capacity of 1 MW when 

aggregated, as in the proposed model 

rule). 

For non-metered units of less than 10 

Kilowatt, we request 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 

request broad comment on the 

appropriate estimating software or 

algorithms and the appropriate 

characteristics for such estimating 

software or algorithms. 

We request comment on any other 

requirements that should be included in 

the final model rule regarding EM&V of 

RE resources. 

For all energy generating resources 

(such as RE, but also including 

applicable resources requiring EM&V 

described below), we request 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 meters on units of less than 10 

Kilowatt, at the AC output of the 

inverter or elsewhere), whether 

measurement should be before or after 

parasitic load (and how to separate out 

parasitic load). In addition, for all 

energy generating resources, we request 

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 area settlement process, we 

request comment on how the data 

collection should be specified in the 

final model rule. Finally, we request 

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 energy resources, and 

for documenting these requirements in 

EM&V plans and reports are the same as 

the requirements for RE discussed in the 

preceding subsection. 

The EPA requests comment on all 

metering, measurement, verification, 

and other requirements in this 

subsection, including the 

appropriateness of their use for each 

type of nuclear energy resource 

(including the relevant size and 

distribution of such resource) that 

qualifies for issuance of ERCs for use in 

Clean Power Plan compliance. We 

request comment on whether nuclear 

energy resources should be subject to 

the same EM&V requirements as RE 

resources, and if not, we request 

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81When 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 

subsection titled Biomass EM&V requirements. 

82A CHP facility may consist of one or more 

electric generators. 

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 subsection, 

including metering requirements, 

special treatment for units of less than 

10 Kilowatt, and how to account for 

T&D losses. 

In order to determine the incremental 

CO2 emission rate, a CHP unit would 

monitor CO2 emissions and energy 

output.81 The monitoring requirements 

are standard methods currently in use 

and the requirements would depend on 

the size of the CHP units and the fuel 

used in the unit. 

Non-affected CHP facilities 82 with 

electric generating capacity greater than 

25 MW would follow the same 

monitoring and reporting protocols for 

CO2 emissions and energy output as are 

required for affected EGU CHP units. 

These requirements are discussed in 

section IV.D.13 of this preamble. For 

non-affected CHP facilities with electric 

generating capacity less than or equal to 

25 MW, which use only natural gas and/ 

or distillate fuel oil, the low mass 

emission unit CO2 emission monitoring 

and reporting methodology outlined in 

40 CFR part 75 is acceptable. 

The EPA requests comment on all 

metering, measurement, verification, 

and other requirements included in this 

subsection with respect to CHP, 

including the appropriateness of their 

use for CHP (including with respect to 

the size of the CHP resource). We 

request comment on whether a CHP unit 

should be subject to the same EM&V 

requirements as RE resources, and we 

request comment on any additional 

EM&V requirements to which CHP units 

should be subject. Specifically, we 

request comment on specifying in the 

final model rule that if a CHP unit has 

an electric generating capacity greater 

than 25 MW, its EM&V plan must 

specify that it will meet the 

requirements that apply to an affected 

EGU under 40 CFR 62.16540. We also 

request comment on specifying in the 

final model rule that if a CHP unit has 

an electric generating capacity less than 

or equal to 25 MW, the EM&V plan must 

specify that it will meet the low mass 

emission unit CO2 emission monitoring 

and reporting methodology in 40 CFR 

part 75. We request comment on any 

alternatives to these measurement 

methodologies that should be specified 

in the final model rule. We request 

comment on any other requirements 

that should be included in the final 

model rule regarding EM&V of CHP. 

e. Biomass EM&V Requirements. A 

state plan that is adopting the rate-based 

model rule must propose EM&V 

requirements for monitoring and 

reporting biogenic CO2 emissions from 

the use of qualified biomass at RE 

facilities that are eligible for adjusting a 

CO2 emission rate. If a state proposes to 

use the monitoring and reporting 

requirements for biogenic CO2

emissions in 40 CFR part 98 (40 CFR 

98.3(c), 98.36(b)–(d), 98.43(b), and 

98.46) in its plan submission, those 

requirements are presumptively 

approvable. An EM&V plan that 

addresses biomass RE must follow the 

requirements for monitoring and 

reporting biogenic CO2 emissions from 

the facility that were approved by the 

EPA in connection with the specific 

state plan. 

The EPA requests comment on all 

metering, measurement, verification, 

and other requirements included in this 

subsection with respect to biomass, 

including the appropriateness of their 

use for qualified biomass. We request 

broad comment on the types of qualified 

biomass feedstocks that should be 

specified in the final model rule, if any. 

We request comment on the methods 

that we should specify in the final 

model rule for the measurement of the 

associated biogenic CO2 for such 

feedstocks, as well as what other 

requirements we should specify in the 

final model rule related to qualfied 

biomass. We request comment on any 

other requirements that should be 

included in the final model rule 

regarding EM&V for qualified biomass. 

Detailed discussion on the role of 

qualified biomass feedstocks can be 

found in section IV.C.3 of this preamble. 

f. Waste-to-Energy EM&V 

Requirements. A state plan that is 

adopting the rate-based model rule must 

propose EM&V requirements for 

monitoring and reporting biogenic CO2

emissions from waste-to-energy 

facilities that are eligible for adjusting a 

CO2 emission rate. If a state proposes to 

include the monitoring and reporting 

requirements for biogenic CO2

emissions in 40 CFR part 98 (40 CFR 

98.3(c), 98.36(b)–(d), 98.43(b), and 

98.46) in its plan submission, those 

requirements are presumptively 

approvable. The EPA may approve other 

requirements of similar rigor, at its 

discretion. An EM&V plan that 

addresses the biogenic CO2 emissions 

from a waste-to-energy facility must 

follow the requirements for monitoring 

and reporting biogenic CO2 emissions 

from the facility that were approved by 

the EPA in connection with the specific 

state plan. 

As discussed in the final EGs (see 

section VIII.K.1 of the final EGs), only 

the portion of electric generation at a 

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 waste-toenergy, including the appropriateness of 

their use for waste-to-energy. We 

request comment on whether a waste-toenergy resource should be subject to the 

same EM&V as RE resources, and we 

request comment on any additional 

EM&V requirements to which waste-toenergy resources should be subject, 

including comment on any specific 

methods for determining the specific 

portion of the total net energy output 

from the resource that is related to the 

biogenic portion of the waste that the 

EPA should include in the final model 

rule. 

g. Demand-Side Energy Efficiency 

EM&V Provisions. This subsection 

proposes EM&V provisions that will be 

presumptively approvable if included in 

state regulations governing how EE is to 

be quantified by EE providers and 

verified by independent entities acting 

on behalf of the state. As noted above 

these proposed provisions apply to all 

demand-side EE used to adjust an 

emission rate if a state adopts the model 

rule. The EPA is soliciting comment on 

the incorporation of EE for the federal 

plan and by extension the EM&V 

associated with it. 

For all demand-side EE used to 

generate ERCs, the EPA is proposing 

that the metric is MWh of electricity 

savings, which must be quantified on an 

ex-post or real-time basis and defined as 

a reduction in facility- or premises-level 

electricity consumption due to an EE 

program, project, or measure. 

(1) Common Practice Baseline 

Based on public input and 

assessments of industry best-practice 

protocols and procedures, the EPA is 

proposing that it is presumptively 

approvable to quantify EE savings as the 

difference between actual metered 

electricity usage after an EE program, 

project, or measure is implemented, and 

a ‘‘common practice baseline’’ (CPB). A 

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83T&D losses are defined as the difference 

between the quantified EGU generation required to 

serve a customer’s load (measured at the EGU bus 

bar) and the customer’s actual electricity 

consumption (measured at the customer meter). 

84More information about these technologies is in 

section VIII.F.1 of the final EGs. 

CPB is the equipment that would most 

frequently be installed at the time an 

existing piece of equipment fails or is 

replaced at the end of its effective useful 

life—or that a typical consumer or 

building owner would have continued 

using for the remainder of the 

equipment’s effective useful life—in a 

given circumstance (i.e., a given 

building type, EE program type or 

delivery mechanism, and geographic 

region) at the time of EE 

implementation. It defines what would 

commonly have happened in the 

absence of the EE program, project, or 

measure. 

The applicable CPB depends on a 

number of factors, such as 

characteristics of the EE program, 

project, or measure, the mechanism by 

which electricity customers are engaged, 

local consumer and market 

characteristics, and the applicable 

building energy codes and product 

standards (C&S), including the C&S 

compliance rate. Examples of 

appropriate CPBs to apply in specific 

circumstances, which may be 

presumptively approvable, can be found 

in the EPA’s EM&V guidance. EE 

providers must document the selected 

CPB in their EM&V plans, along with 

clear documentation and discussion of 

the rationale, applicability, and relevant 

data sources, protocols, and other 

supporting information. Monitoring and 

verification reports must refer to the 

EM&V plan and confirm that the CPB 

was appropriately applied. 

(2) Methods Used To Quantify Savings 

From Energy Efficiency Programs and 

Projects 

This section proposes criteria that are 

presumptively approvable for the 

general types of EM&V methods that EE 

providers may use to quantify the MWh 

savings from demand-side EE programs, 

projects, and measures. During the 

Clean Power Plan EG’s public comment 

period, the EPA received input 

indicating that state PUCs typically 

allow utilities and other EE providers to 

use a range of EM&V methods that 

reflect applicable circumstances and onthe-ground conditions (versus 

mandating which methods must be used 

in a particular situation). Consistent 

with this approach, the EPA is 

proposing to offer flexibility for EE 

providers to select from three broad 

categories of EM&V methods to 

determine savings. 

These categories include projectbased M&V, deemed savings, and 

comparison group approaches such as 

randomized control trials (RCT). 

Regardless of the approach selected, the 

EPA is proposing that annual savings 

values must be quantified using these 

EM&V methods at specified time 

intervals (in years) on a recurring basis 

over the effective useful life of the EE 

project or measure in order to ensure 

accurate and reliable savings values. To 

be presumptivey approable, the EPA is 

proposing that EE providers must apply 

the above methods at a minimum of 4- 

year intervals for building energy codes 

and product standards; every 1, 2, or 3 

years for publicly- or utilityadministered EE programs, depending 

on the program type, magnitude of 

savings, and experience with the 

program; and annually for large 

individual commercial and industrial 

projects, unless the EE provider can 

credibly demonstrate why this is not 

possible and how the accuracy and 

reliability of savings values will be 

maintained. The EPA is further 

proposing that, to be presumptively 

approvable, the selected method, 

associated assumptions, and data 

sources must be identified and 

described in EM&V plans. 

For comparison group approaches, the 

EPA is propsing that states and EE 

providers can refer to the EPA’s draft 

EM&V guidance for a discussion of 

industry best-practice protocols and 

guidelines. Where feasible, the EPA is 

proposing to encourage the use of RCT 

methods, which determine savings on 

the basis of energy consumption 

differences between a treatment group 

and a comparison group, and therefore 

increase the reliability of results. 

As noted above, an alternative to 

comparison group methods is the use of 

deemed savings values, which establish 

pre-determined annual electricity 

savings values for specific EE measures. 

The EPA is proposing that the use of 

deemed savings values would be 

presumptively approvable if those 

values (a) are documented in a publicly 

available database (also known as a 

Technical Reference Manual (TRM)) 

that is accessible on a public Web site, 

or is otherwise readily accessible; (b) 

specify the conditions for which each 

deemed value can be applied, including 

but not limited to climate zone, building 

type, and EE implementation 

mechanism; and (c) are updated at a 

minimum of every 3 years to reflect the 

per-measure MWh savings documented 

in ex-post EM&V studies that apply 

M&V or comparison group methods. 

For M&V methods to be 

presumptively approvable, the EPA is 

proposing is that industry best-practice 

protocols and/or guidelines must be 

followed. Examples of acceptable bestpractice protocols and guidelines are 

provided in the EPA’s EM&V guidance. 

EE providers can consult the EM&V 

guidance to assess the applicability of 

these technical resources to the EE 

programs and projects generating 

savings, and must document how one or 

more best-practice protocols or 

guidelines will be appropriately applied 

in EM&V plans (along with clear 

documentation and discussion of the 

rationale, applicability, and relevant 

data sources, and other supporting 

information). The EPA is also proposing 

that monitoring and verification reports 

must refer to the EM&V plan and 

confirm that the relevant M&V protocol 

or guideline was properly applied. 

(3) Quantifying Savings 

Regardless of the approach used to 

quantify and verify MWh savings, the 

EPA is proposing that EM&V plans must 

describe how they will address the 

following provisions: 

• How major changes in independent 

variable conditions (weather, 

occupancy, production rates, etc.) that 

affect energy consumption and savings 

estimates will be accounted for. The 

EPA is proposing that the effects of 

these changes must be calculated using 

industry best-practices such as real-time 

conditions or normalized conditions 

that are reasonably expected to occur 

throughout the lifetime of the EE project 

or measure. 

• How the initial installation of EE 

will be verified for EE program 

categories that involve the installation 

of identifiable measures (e.g., most 

utility consumer-funded EE programs 

and project-based EE are evaluated siteby-site). The EPA is proposing that 

verification is required within the first 

year of program implementation and 

that all verification activities must be 

performed using industry 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 larger program, 

the EPA is proposing that verification 

can be performed using a sample of 

projects to represent the full program 

population. 

• How avoided T&D system losses 83

will be quantified and applied to EE 

savings determined at the customer 

facility or premises. The EPA is 

proposing that demand-side EE 

programs (other than T&D efficiency 

measures such as conservation voltage 

regulation or reduction (CVR) and volt/ 

VAR optimization 84) may adjust 

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85Estimated losses in MWh, total electric supply, 

and direct electricity use values are available in the 

U.S. EIA’s State Electricity Profiles. See Table 10 on 

Supply and Disposition of Electricity. 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. 

86Rigor 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. 

reported savings by using a T&D adder. 

If such an adder is applied, the 

presumptively approvable approach is 

to use the smaller of 6 percent or the 

calculated statewide annual average 

T&D loss rate (expressed as a 

percentage) calculated using the most 

recent data published by the U.S. EIA 

State Electricity Profile.85

• How the duration of EE program or 

project electricity savings will be 

determined. This must be determined 

using industry best-practice protocols 

and procedures involving annual 

verification assessments, 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 rigor 86 of the methods 

used to control the types of bias or error 

inherent to the applied EM&V methods. 

Sampling of populations is appropriate, 

provided that the quantified MWh 

derived from sampling have at least 90 

percent confidence intervals whose end 

points are no more than +/¥10 percent 

of the estimate. 

• How double counting will be 

avoided through the use of tracking and 

accounting procedures to ensure that 

the same MWh of electricity savings is 

not claimed more than one time (for 

example, two EGUs claiming savings 

from the same lighting retrofit). The 

types of double counting that may arise 

are discussed in the EPA’s draft EM&V 

guidance. 

(4) Use of Energy Efficiency EM&V 

Protocols 

In the Clean Power Plan 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 demandside EE. In particular, the EPA is 

proposing that, to be presumptively 

approvable, EM&V plans must specify 

the use of best-practice protocols and 

procedures, and must also include a 

clear description and documentation of 

how the relevant protocols and 

procedures will be applied. EM&V 

reports must include documentation of 

how such protocols and procedures 

were actually applied. EE providers can 

refer to the EPA’s EM&V guidance 

document for information about 

protocols that are considered ‘‘industry 

best-practice protocols and procedures.’’ 

(5) Eligible Demand-Side Energy 

Efficiency (DS–EE) Programs and 

Projects 

There has been stakeholder interest 

expressed through the Clean Power Plan 

EGs rulemaking process in allowing 

states to issue ERCs for quantified and 

verified MWh savings from DS–EE 

under state plans. Consistent with these 

perspectives, the EPA is proposing that 

any demand-side EE program, project, 

or measure that results in MWh savings 

may be potentially eligible to generate 

ERCs, including under this proposed 

model trading rule, provided that they 

meet the presumptively approvable 

provisions for eligibility described in 

section IV.C.3 of this preamble, and that 

supporting EM&V is rigorous, 

transparent, credible, complete and 

fulfills the requirements provided in the 

EGs and the state plan. Examples of 

potentially eligible demand-side EE 

program and project types include: 

• Publicly or utility-administered EE 

programs, including those implemented 

in low-income residences and facilities. 

• Project-based EE evaluated site-bysite, for example those implemented by 

ESCOs at commercial buildings and 

industrial facilities. 

• State and local government building 

energy code and compliance programs. 

• State and local government 

incremental product energy standards. 

The EPA’s EM&V guidance contains 

supplemental information about 

applicable best-practice protocols, 

methods, and other key considerations 

for quantifying and verifying savings 

from the above-listed EE activities in an 

accurate and reliable manner. The 

agency also recognizes that the 

programs and policies listed above will 

evolve and change over the rule period, 

as new technologies emerge and 

efficiency improves. The agency also 

expects that new EE program types will 

emerge and expand throughout the rule 

period, and that MWh savings resulting 

from any such programs can similarly 

be considered if they meet the 

requirements of the EGs. 

(6) Requests for Comment on Energy 

Efficiency EM&V 

We request broad comment on each 

EE EM&V criterion described herein and 

in the proposed rule text, for each type 

of EE activity, project, program, or 

measure. Specifically, we seek comment 

on the substantive content of the 

criteria, and we seek comment on the 

level of detail provided regarding these 

criteria and whether more or less detail 

(and what detail) should be included in 

the final model rule. In addition, we 

seek comment on whether some of the 

EE EM&V criteria (and if so, which 

criteria) included in the draft guidance 

document released simultaneously with 

this proposed rulemaking should 

instead be included in the final model 

rule, instead of in guidance. Similarly, 

we seek comment on whether some of 

the EE EM&V criteria (and if so, which 

criteria) included in the proposed model 

rule should instead be addressed in the 

final EM&V guidance. More generally, 

we seek comment on what EE criteria 

the EPA should described in guidance 

versus what criteria the EPA should 

specify in the final model rule, whether 

or not those criteria are already 

included in the draft guidance or 

proposed model rule. 

We request broad comment on the 

appropriate EE EM&V criteria for 

quantifying the electricity savings from 

every type of EE program, project, or 

measure. We request broad comment on 

what constitute EE best-practice 

protocols and procedures for every type 

of EE program, project, or measure. 

We request broad comment on 

whether, when, and how common 

practice baselines should and should 

not be used in calculating electricity 

savings from EE activities, projects, 

programs, and measures, including 

comment on which common practice 

baselines should be used in which 

circumstances. We also request 

comment on whether some alternative 

metric should be used in lieu of the 

common practice baseline and, if so, 

what that metric should be. 

We request 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 RCT and quasiexperimental methods, and the 

circumstances in which they can be 

encouraged and applied in practice (e.g., 

when a suitable control or comparison 

group can be identified and applied in 

a cost-effective manner). In addition, we 

request comment on whether the 

general suitability and applicaton of 

quantification methods, such as RCT, 

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quasi-experimental techniques or other 

comparison group approaches when 

they are available at reasonable cost for 

purposes of quantifying MWh savings 

for particular EE programs, projects, or 

measures. 

If deemed savings are to be used in 

quantifying electricity savings from an 

EE program, project, or measure, we 

request comment on the appropriate 

characteristics and presumptively 

approvable provisions for their use in 

generating qualifying ERCs, including 

the basis and frequency for their 

determination, and the appropriateness 

of their application to particular EE 

programs, projects or measures in 

particular states or regions. We further 

request comment on the presumptively 

approvable provision for public access 

and input to the development of the 

technical reference manuals (TRMs) 

used to house the applicable deemed 

savings values. 

We request 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 request comment on 

any factors that must be taken into 

consideration when determining the 

appropriate time interval for specific EE 

programs, projects, or measures. 

Because many states have different EE 

programs in place today, and we would 

expect them to leverage these programs 

if they incorporated EE into a rate-based 

trading scheme with ERCs, it is 

theoretically possible that an ERC could 

be issued in one state that would not 

have been issued in another, even if 

both states have rate-based programs in 

place that meet all of the EGs. The EPA 

requests comment on what criteria it 

should include in the final model rule, 

and what level of details with respect to 

those criteria that it should include, in 

order to ensure that an ERC issued for 

an EE program, project, or measure in 

one state reflects the same MWh of 

energy or electricity saved in another 

state. We further request comment on 

whether there are provisions that the 

EPA should include in the final model 

rule that would prevent an entity 

seeking to be issued an ERC (whether 

from EE or energy generation) from 

forum shopping, in an effort to find a 

state with standards for ERC issuance 

that it deems more lenient or less 

burdensome than those in another state. 

We request 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 request 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 request 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 request comment on the 

appropriate steps for avoiding double 

counting, and how such steps should be 

documented in an EM&V plan. In 

particular, we request comment on the 

circumstances and conditions in which 

double counting is most likely to occur 

(including those identified in this 

section), and the presumptively 

approvable provisions that must be 

adopted in state plans for avoiding and 

mitigating double counting. 

We request comment on the 

appropriate means by which an EM&V 

plan can ensure the accuracy and 

reliability of electricity savings 

estimates, including the necessary rigor 

of the methods selected to evaluate the 

electricity savings, the methods used to 

control all relevant types of bias and to 

minimize the potential for systematic 

and random error, and the potential 

effects of such bias and error. We further 

request comment on the presumptively 

approvable provision that samples taken 

to quantify EE program savings must 

achieve 90/10 confidence and precision. 

We request comment on the 

presumptively approvable approach to 

quantifying the electricity savings that 

result from avoiding a transmission and 

distribution system loss, including the 

provisions in the proposed model rule, 

which specify that each EM&V plan 

must quantify the transmission and 

distribution loss based on the lesser of 

6 percent of the site-level electricity 

consumption measured at the end use 

meter or the statewide annual average 

transmission and distribution loss rate 

(expressed as a percentage) from the 

most recent year that is published in the 

U.S. EIA State Electricity Profile. We 

request comment on the appropriateness 

of including a restriction in the final 

model rule that no other transmission 

and distribution loss factors may be 

used in calculating the electricity 

savings. 

We request comment on any 

additional criteria that we should 

include in the final model rule 

regarding EE EM&V. 

h. Skill Certification Standards. Using 

a skilled workforce to implement 

demand-side EE and RE projects and 

other measures intended to reduce CO2

emissions, and to evaluate, measure and 

verify the savings associated with EE 

projects or the additional generation 

from performance improvements at 

existing EGU’s are both important. 

Several commenters on the EGs 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 emission 

reductions. 

The EPA agrees that in conjunction 

with other EM&V measures discussed in 

this section, and in the context of the 

model trading rules although this is not 

an aspect needed for presumptive 

approvability, states are encouraged to 

include in their plan a description of 

how states will ensure that workers 

installing demand side EE and RE 

projects, or other measures intended to 

reduce CO2 emissions, as well as 

workers who perform the EM&V of 

demand side EE and existing EGU 

performance will be certified by a third 

party entity that: 

• Develops a training or competency 

based program aligned with a job task 

analysis and/or certification scheme; 

• Engages with subject matter experts 

in the development of the job task 

analysis and/or certification schemes 

that represent appropriate 

qualifications, categories of the jobs, and 

levels of experience; 

• Has clearly documented the process 

used to develop the job task analysis 

and/or certification schemes, covering 

such elements as the job description, 

knowledge, skills, and abilities; 

• Has pursued third-party 

accreditation aligned with consensusbased standards, for example ISO/IEC 

17024 or IREC 14732. 

Examples of such entities include: 

Parties aligned with the DOE’s Better 

Building Workforce Guidelines and 

validated by a third party accrediting 

body recognized by DOE; or parties 

aligned with an apprenticeship program 

that is registered with the federal DOL, 

Office of Apprenticeship; or parties 

aligned with a state apprenticeship 

program approved by the DOL, or by 

another skill certification validated by a 

third party accrediting body. Entities 

such as these can help to substantiate 

the authenticity of emission reductions 

due to demand-side EE and RE and 

other carbon emission reduction 

measures. 

9. ERC Transfers and Trading 

All affected EGUs that may be subject 

to this proposed federal plan would be 

required to be a part of the ATCS that 

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87See section IV.D.11 of this preamble for more 

information. 88This true-up process is further described in 

section IV.D.10 of this preamble. 

89The ‘‘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. 

the EPA runs, although the affected 

EGUs that are regulated under the ratebased federal plan would use ERCs as a 

compliance instrument, not allowances. 

To register to participate in the ATCS an 

affected EGU must submit designated 

representative information. More 

information on the designated 

representatives is described above in 

section IV.D.1 of this preamble. NonEGUs 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 Clean Power Plan 

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 75.87

These quarterly submission dates are 

the 30th of April, July, October and 

January corresponding with the 

quarterly data ending the month 

previous the submission deadline (e.g., 

an April 30, 2024 submission would 

include data from January through 

March of 2024). The data that are posted 

online would be publicly available. 

Non-EGU ERC generating sources are 

required to submit generation data 

annually (see section IV.C.3 of this 

preamble for a comprehensive 

discussion of non-EGU ERC generating 

sources). The data must follow the 

EM&V procedures delineated in section 

IV.D.8 of this preamble. Because of the 

required rigor of the EM&V process, the 

EPA provides a time frame of January 1 

to June 1 of the year that follows the 

data’s inception to complete all EM&V 

processes (e.g, 2024 RE data must go 

through the EM&V process and be 

submitted to the EPA no later than June 

1, 2025). After receiving all emission 

and generation data from ERC 

generating sources and affected EGUs, 

the EPA will issue ERCs through a 

NODA as described in section IV.D.6 of 

this preamble. The EPA is proposing to 

issue ERCs annually. ERCs are acquired 

and traded throughout the compliance 

period. An affected EGU is responsible 

to hold sufficient ERCs that qualify for 

Clean Power Plan compliance in its 

ATCS compliance account by November 

1 at midnight of the year following the 

conclusion of the compliance period.88

The process for transferring ERCs 

from one account to another is quite 

simple. A transfer would be submitted 

providing, in a format prescribed by the 

agency, the account numbers of the 

accounts involved, the serial numbers of 

the ERCs involved, and the name and 

signature of the transferring authorized 

account representative or alternate. If 

the transfer form containing all the 

required information were submitted to 

the EPA and, when the Administrator 

attempted to record the transfer, the 

transferor account included the ERCs 

identified in the form, the Administrator 

would record the transfer by moving the 

ERCs from the transferor account to the 

transferee account within 5 business 

days of the receipt of the transfer form. 

10. Compliance With Emissions 

Standards 

Once the compliance period has 

ended, affected EGUs would have a 

window of opportunity to evaluate their 

reported emissions and obtain any ERCs 

that they might need to cover their 

emissions during the compliance 

period. The agency proposes to require 

sources to demonstrate compliance, i.e., 

ERC true-up, on November 1 of the year 

after the last year in the compliance 

period. For example, if the first 

compliance period comprises the three 

years 2022, 2023, and 2024, then the 

ERC transfer deadline 89 for that first 

compliance period (after which point 

the EPA would evaluate compliance) 

would be on November 1, 2025. The 

agency also requests comment on an 

earlier ERC transfer deadline, such as 

June 1 or March 1, of the year after the 

last year in the compliance period. Each 

ERC issued in the proposed rate-based 

trading program would, if applied, be 

averaged into the compliance rate as one 

MWh of energy with zero CO2 emissions 

deemed associated with it for the 

compliance period that includes the 

year for which the ERC was issued or be 

averaged into a later compliance period. 

Consequently, each affected EGU would 

need, as of the ERC transfer deadline, to 

have in its compliance account enough 

ERCs usable for its compliance 

obligations for the compliance period. 

The authorized account representative 

could identify specific ERCs to be 

applied, but, in the absence of such 

identification or in the case of a partial 

identification, the Administrator would 

deduct on a first-in, first-out basis. The 

ERCs that are used to meet compliance 

obligations are moved from the 

compliance account to the EPA’s 

retirement account. ERCs that are 

deducted for compliance will remain in 

the system in an EPA account, which 

ensures they will not be used again. 

The EPA will use the submitted 

generation, CO2 emissions and ERCs in 

the affected EGU’s compliance account 

to calculate an average emission rate for 

the EGU. It is the responsibility of an 

affected EGU to calculate the number of 

ERCs that will need to be held in a 

compliance account to meet the EGU’s 

compliance obligations. The method for 

determining the quantity of ERCs 

needed to meet compliance obligations 

has been discussed previously in an 

example. To reiterate the process, the 

affected EGU would need to solve for 

the number of zero-emitting MWh (i.e., 

ERCs) that would need to be added to 

the total MWh of the EGU to make the 

adjusted emission rate equal to the 

emission standard. 


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If an affected EGU fails to hold 

sufficient ERCs to comply with its 

emission standard then, upon 

notification of the deficiency, the 

owners and operators of the affected 

EGU must provide, for deduction by the 

Administrator, two ERCs as soon as 

available for every ERC that the owners 

and operators failed to hold as required 

to cover emissions, in addition to the 

ERCs owed for compliance in that next 

period. The owed ERCs will be 

deducted from the EGU’s compliance 

account as soon as they are available in 

this account; the Administrator will not 

wait until the next true-up date to make 

this deduction. The two ERCs owed for 

each ERC needed for compliance but not 

supplied is in addition to any other 

recourse provided in sections 113(a)–(h) 

or section 304 of the CAA. This 

requirement to surrender two times the 

ERCs needed to make up the shortfall 

for the prior period is an ongoing 

obligation until compliance is achieved, 

and there is an ongoing obligation to 

comply in the current period. Failure to 

surrender these replacement ERCs is an 

additional violation that may be subject 

to federal enforcement. The EPA solicits 

comment on sources owing two ERCs to 

make up for each insufficient ERC in 

previous compliance periods and 

whether two for one is the proper makeup rate or whether there should be a 

stricter or a more lenient ratio. 

The EPA believes that it is important 

to include a requirement for an 

automatic deduction of ERCs. The 

deduction of one ERC per ERC that the 

owners and operators failed to hold 

would offset this failure. The deduction 

of another ERC per ERC that the owners 

and operators failed to hold provides a 

strong incentive for compliance with the 

ERC-holding requirement by ensuring 

that non-compliance would be a 

significantly more expensive option 

than compliance. This is consistent with 

other existing trading programs. 

11. Other ERC Tracking and Compliance 

Operations Provisions 

These sections also would provide 

that the Administrator could, at his or 

her discretion and on his or her own 

motion and consistent with existing 

federal trading programs, correct any 

type of error that he or she finds in an 

account in the ATCS. In addition, the 

Administrator could review any 

submission under the rate-based trading 

program, make adjustments to the 

information in the submission, and 

deduct or transfer ERCs based on such 

adjusted information. These provisions 

are a standard part of other trading 

programs administered by the EPA 

including the ARP and the CSAPR (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 may be simpler or more 

efficient. 

12. Banking of ERCs 

The EPA is proposing to allow 

unlimited banking of ERCs within and 

between the interim and final 

compliance periods. This means that if 

an affected EGU has more ERCs than are 

necessary during true-up, it may save 

(i.e., bank) those ERCs for application 

during a future compliance period. The 

EPA requests comment on whether 

there should be a quantitative limit or 

cap on the number of ERCs that can be 

banked. The EPA also requests comment 

on whether an ERC should be eligible to 

be banked between the interim and final 

compliance periods. The EPA is also 

proposing that ERCs will not expire 

after any duration of time. Other trading 

rules that the EPA has instituted (e.g., 

CSAPR) do not have expiration on the 

tradable properties. The EPA requests 

comment on the shelf-life of an ERC. 

ERC ‘‘borrowing’’ is a flexibility that 

the EPA is not proposing, but is 

soliciting comment on. ERC borrowing 

is the concept that an affected EGU may 

use an ERC that the EGU will 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 

concerning this concept due to the fact 

that future ERC generation is not 

guaranteed. 

13. Emissions Monitoring and Reporting 

The EPA would require that emission 

and generation data be reported to the 

EPA quarterly starting on April 30, 

2022, and continuing every 3 months 

thereafter (i.e., the 30th of April, July, 

October, and January). The EPA 

proposes that affected EGUs subject to 

the rate-based federal plan trading 

program would monitor and report CO2

emissions in accordance with 40 CFR 

part 75. The EPA is proposing to require 

affected EGUs in all states covered by 

the rate-based federal plan trading 

program to monitor and report CO2

emissions by and output data by January 

1, 2022. Quarterly reporting would be 

required, with each quarterly report due 

to the Administrator 30 days after the 

last day in the quarter. The reporting 

would be in accordance with 40 CFR 

75.60. The use of 40 CFR part 75 

certified monitoring methodologies 

would be required. Many affected EGUs 

that might be covered by the proposed 

federal plans will generally have no 

changes to their monitoring and 

reporting requirements and will 

continue to monitor and submit reports 

under 40 CFR part 75 as they have 

under existing programs. The EPA 

anticipates fewer than 50 

(approximately 10 of these affected 

EGUs are coal fired with the remainder 

being gas and oil fired that will qualify 

for an excepted monitoring 

methodology) affected EGUs, that would 

not otherwise be subject to the ARP, 

will have to purchase and install 

additional continuous emissions 

monitoring system (CEMS) and data 

handling systems or upgrade existing 

equipment in order to meet the 

monitoring and reporting requirements 

of this program. Several of the affected 

EGUs not otherwise subject to the ARP 

are subject to the MATS program and 

therefore will have already installed 

stack flow rate and/or CO2 monitors in 

order to comply with the MATS rule 

which are also necessary to comply with 

this rule. The CEMS used to comply and 

report data for MATS will be used for 

this rule to generate and report CO2

emissions data without having to install 

duplicative monitors. The same CO2 and 

stack gas flow rate monitored data used 

in conjunction with mercury and other 

CEMS to calculate a toxic pollutant 

emission rate may be used to calculate 

a CO2 mass or CO2 emission rate for this 

program. The Regional Greenhouse Gas 

Initiative (RGGI), ARP, MATS and this 

rule all refer to CEMS installed and 

certified in accordance with 40 CFR part 

75. RGGI and ARP currently require the 

reporting of CO2 mass emissions on an 

hourly basis and cumulative totals at the 

end of each calendar quarter. The same 

monitors and data collected may be 

used for multiple purposes for RGGI, 

ARP, MATS and this rule. Relying on 

the same monitors that are certified and 

quality assured in accordance with 40 

CFR part 75 ensures cost efficient, 

consistent, and accurate data that may 

be used for different purposes for 

multiple regulatory programs. The 

majority of the affected EGUs covered 

by this rule are already affected by the 

Acid Rain and/or RGGI programs and 

will have minimal additional 

monitoring and reporting requirements. 

The EPA also requests comment on 

requiring monitoring and reporting of 

CO2 mass and net generation for the 

year before the initial compliance 

period begins, i.e., to commence January 

1, 2021. Only monitoring and reporting 

would be required in 2021—compliance 

with an enforceable emission standard 

would commence on the compliance 

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period schedule that is detailed in 

section III.D of this preamble. 

E. Federal Plan and State Plan 

Interactions 

1. Interstate Trading 

The EPA proposes that all affected 

EGUs within states that are covered by 

the federal plan, if a rate-based federal 

plan is finalized for two or more states, 

would be allowed to trade with one 

another since there will be an assured 

commonality in the ERC currency and 

criteria surrounding the trading 

program. In addition, the EPA proposes, 

consistent with the provision for 

‘‘ready-for-interstate-trading’’ plans in 

the EGs, that affected EGUs located in 

states with approved ready-forinterstate-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 ready-forinterstate-trading state plans will be able 

to trade ERCs seamlessly across 

jurisdictional borders because of the 

assurances of being presumptively 

approvable. Ready-for-interstate-trading 

states must submit information that lists 

all affected EGUs and the EGU type to 

the Administrator to be able to trade 

within the federal trading program. To 

be able to trade in the federal trading 

program an affected EGU that is subject 

to a ready-for-interstate-trading state 

plan must: (1) Certify and authorize a 

designated representative per section 

IV.D.1 of this preamble; and (2) register 

a general account in the federal trading 

program, ATCS, in order to have a 

means of transferring 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 affected EGU’s 

corresponding state plan. Affected EGUs 

under a state plan have the ability to 

acquire ERCs through the federal trading 

program. These ERCs will be stored in 

the EGU’s general account in the federal 

trading program. To use these ERCs for 

compliance purposes, the ERCs must be 

transferred to the EGU’s compliance 

account in the state’s program. The EPA 

proposes to provide software to states to 

maintain a state’s compliance and 

tracking program. A state’s program will 

have the capability to interact with the 

federal trading program and software, 

ATCS, for transferring ERCs if the state 

is ready-for-interstate-trading. A state’s 

program can be tailored to meet its 

needs while still providing a platform 

for a state to be transferring ERCs 

between the state’s system and the 

federal trading program. ERCs can flow 

between a state system and the federal 

trading program bilaterally. The EPA 

acknowledges that states may have 

additional criteria for generating ERCs 

that are not outlined as part of the 

federal plan, but because the EPA will 

have vetted these criteria through a state 

plan approval these ERCs will be able to 

be traded within the federal trading 

program. 

2. Treatment of States Entering or 

Exiting the Trading Program 

The EPA proposes that a rate-based 

trading federal plan may be replaced by 

a state plan for a future compliance 

period. The EPA is proposing that a 

state must transition to a state plan at 

the conclusion of a federal plan 

compliance period. The EPA requests 

comment on whether there are reasons 

that a state should be allowed to 

transition from a federal plan to a state 

plan in the middle of a compliance 

period and if so what requirements 

should be put in place to do so while 

ensuring the integrity of both the federal 

plan and the state plan and while 

enabling the affected EGUs covered by 

the plans to understand and meet their 

compliance requirements. If a state 

subject to the federal plan transitions to 

a state plan, any affected EGU impacted 

by the change remains responsible for 

meeting any outstanding obligations 

under the federal plan. To make the 

transition to a state plan, a state must 

have an approved state plan as laid out 

in sections VIII.D and VIII.E of the final 

EGs. 

V. Mass-Based Implementation 

Approach 

A. Trading Program Overview 

In addition to the rate-based 

implementation approach discussed 

above, the EPA is proposing a massbased implementation approach for the 

federal plan. As with the rate-based 

approach, this proposed federal plan is 

also a proposed model trading rule that 

states can adopt. The mass-based 

approach that the agency proposes to 

implement is a mass-based trading 

program (i.e., an emissions budget 

trading program, also referred to as an 

‘‘allowance system’’). This section 

provides a brief overview of the 

proposed mass-based trading program. 

The next sections describe the various 

elements of the proposed trading 

program in further detail. 

A mass-based trading program 

establishes an ‘‘aggregate emissions 

limit’’ that specifies the maximum 

amount of emissions authorized from 

affected EGUs included in the program, 

and creates allowances that authorize a 

specific quantity of emissions. The total 

number of allowances created are equal 

to, and constitute, the emissions budget 

or the aggregated emissions limit 

expressed in terms of short tons of 

emissions. The EPA is proposing that 

allowances be issued in short tons for 

the federal plan. 

Each facility with affected EGUs in 

the program must surrender allowances 

equal in number to the quantity of the 

emissions of its affected EGUs during 

the compliance period. A facility with 

affected EGUs may buy allowances 

from, or transfer or sell allowances to, 

other affected EGUs or other entities 

that participate in the market. A massbased trading program provides sources 

with great flexibility in choosing 

compliance strategies. 

In the proposed mass-based trading 

program for the federal plan, the 

aggregate emissions limit for a state is 

its statewide mass-based emission goal 

(or ‘‘mass goal’’) as finalized in the 

Clean Power Plan EGs. The proposed 

approach to linking states for interstate 

allowance trading is detailed in section 

III.A.1 of this preamble; in an interstate 

trading program the aggregate emissions 

limit is the sum of the mass goals for the 

covered states. 

The EPA believes that a broad trading 

region provides greater opportunities for 

cost-effective implementation of 

controls compared to a smaller region. 

Therefore, the agency proposes that an 

affected EGU in any state covered by the 

proposed mass-based trading federal 

plan may use for compliance an 

allowance distributed in any other state 

covered by the mass-based trading 

federal plan. The EPA also proposes to 

provide for allowance trading between 

affected EGUs and other entities in 

states with approved mass-based-trading 

state plans that meet the conditions 

specified in section III.A.1 of this 

preamble, above, and affected EGUs and 

other entities in any state covered by the 

federal plan mass-based trading 

program. 

A mass-based trading program can 

provide environmental certainty at 

lower cost than other policy 

mechanisms, because it assures the 

specified emissions outcome while 

maximizing compliance flexibility 

available to individual affected EGUs. 

Further, allowance banking in such a 

program creates an incentive to make 

reductions earlier than required. Massbased trading programs are relatively 

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simple to operate, which reduces 

administrative time and cost. 

Additionally, to inform the mass-based 

trading approach proposed here, the 

EPA draws upon more than two decades 

of experience implementing federallyadministered mass-based emissions 

budget trading programs including the 

ARP SO2 trading program, the NOX

Budget Trading Program, CAIR, and 

CSAPR. 

In the proposed mass-based trading 

program federal plans, the emissions 

limits in each state would be the mass 

goals that the EPA promulgated in the 

Clean Power Plan EGs (if there is 

interstate trading then the sum of the 

mass goals for the states in the trading 

program would constitute the aggregate 

emissions limit). The total amount of 

allowances distributed in each state for 

each year would sum to the state’s mass 

goal for that year. As detailed in section 

V.E of this preamble, the EPA is 

proposing that a state covered by the 

federal plan can determine its own 

approach to distribute allowances, and 

believes that state allocation has 

important merits. The EPA would 

distribute allowances in a state if the 

state does not choose to do so, as 

detailed below. 

Each allowance would authorize the 

emission of one short ton of CO2 during 

the compliance period applicable to the 

allowance’s vintage year or a later 

compliance period. The proposed 

approach to distribute allowances, 

including three types of allowance setasides, is discussed in section V.D of 

this preamble, below. 

After each compliance period, an 

affected EGU would surrender for 

compliance an amount of allowances 

equal to its emissions during the course 

of the compliance period. See section 

V.C of this preamble for the proposed 

length of the multi-year compliance 

periods. Allowances could be 

transferred, bought, sold, or banked 

(carried over for future use) and any 

party could participate in the allowance 

market. The EPA is not proposing 

allowance ‘‘borrowing’’ (i.e., the 

bringing forward of future-period 

allowances for use in an earlier period); 

the multi-year compliance periods 

inherently provide the flexibility to 

schedule relatively greater emission 

reductions for later years within each 

period, as discussed further in section 

V.C of this preamble. In the proposed 

mass-based trading program, the 

emission standard applied to individual 

affected EGUs is the requirement to 

surrender emission allowances equal to 

reported emissions for each compliance 

period. 

The EPA also proposes that a state 

may choose to replace the federal plan 

allowance-distribution provisions with 

its own allowance-distribution 

provisions (i.e., to determine the 

distribution of allowances for its EGUs 

or other entities) using a state 

allowance-distribution methodology. 

State allowance distribution can have 

important advantages, because it allows 

a state to design and shape allowance 

allocation to its specific goals and 

characteristics, and because states may 

have additional flexibility on allocation 

approaches, including auctions. See 

section V.E of this preamble for further 

discussion of the proposed approach for 

state-determined allowance-distribution 

methodologies. 

This proposed requirement to hold 

and surrender allowances equal to 

emissions for each compliance period 

would apply to all reported emissions 

from a facility’s affected EGUs including 

any emissions from co-fired biomass if 

biomass is included as an eligible 

measure. Section IV.C.3 of this preamble 

discusses an approach on which the 

EPA requests comment on the inclusion 

of biomass as an eligible measure and 

on a proposed option where the agency 

would identify qualified biomass 

feedstocks (i.e., biomass feedstocks that 

are demonstrated to be a method to 

control increases of CO2 levels in the 

atmosphere) and potential methods for 

demonstrating compliance, and thus 

reduce the mass emissions attributed to 

a biomass co-fired affected EGU. If the 

EPA took such an approach, then for 

purposes of compliance with the 

proposed mass-based federal plan 

trading program, the affected EGU 

would need to hold allowances equal to 

its emissions less the emissions 

attributed to the co-fired qualified 

biomass; such an approach would 

reduce the number of allowances the 

affected EGU would need to hold to 

demonstrate compliance. The EPA 

requests comment on this approach. 

B. Statewide Mass-Based Emissions 

Goals 

In the Clean Power Plan EGs the EPA 

established statewide mass-based 

emission goals (‘‘mass goals’’) for all 

states that are equivalent to the ratebased goals. As discussed in section V.C 

of this preamble, 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 

3-year compliance periods followed by 

a 2-year compliance period in the 

Interim Period, and successive 2-year 

periods in the Final Period. In the Clean 

Power Plan EGs, the EPA established 

mass goals for all states for this pattern 

of compliance periods. The EPA 

proposes to use those mass goals 

promulgated in the Clean Power Plan 

EGs as the mass limits (i.e., emissions 

budgets) for any state covered by the 

mass-based trading program (or, if 

implementing interstate trading, then 

the EPA would use the sum of a covered 

group of states’ mass goals as the 

aggregate mass limit). The EPA is not 

opening for comment the 

determinations, made in the Clean 

Power Plan EGs, of each state’s mass 

goals. The mass goals are provided for 

convenience in Table 8 of this preamble. 

TABLE 8—STATEWIDE MASS-BASED EMISSION GOALS (‘‘MASS GOALS’’) 

[Short tons] 

State 

Interim period Final period 

Step 1 

2022–2024 

Step 2 

2025–2027 

Step 3 

2028–2029 

2030–2031 

and 

thereafter 

Alabama ........................................................................................................... 66,164,470 60,918,973 58,215,989 56,880,474 

Arizona * ........................................................................................................... 35,189,232 32,371,942 30,906,226 30,170,750 

Arkansas .......................................................................................................... 36,032,671 32,953,521 31,253,744 30,322,632 

California .......................................................................................................... 53,500,107 50,080,840 48,736,877 48,410,120 

Colorado .......................................................................................................... 35,785,322 32,654,483 30,891,824 29,900,397 

Connecticut ...................................................................................................... 7,555,787 7,108,466 6,955,080 6,941,523 

Delaware .......................................................................................................... 5,348,363 4,963,102 4,784,280 4,711,825 

Florida .............................................................................................................. 119,380,477 110,754,683 106,736,177 105,094,704 

Georgia ............................................................................................................ 54,257,931 49,855,082 47,534,817 46,346,846 

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TABLE 8—STATEWIDE MASS-BASED EMISSION GOALS (‘‘MASS GOALS’’)—Continued 

[Short tons] 

State 

Interim period Final period 

Step 1 

2022–2024 

Step 2 

2025–2027 

Step 3 

2028–2029 

2030–2031 

and 

thereafter 

Idaho ................................................................................................................ 1,615,518 1,522,826 1,493,052 1,492,856 

Illinois ............................................................................................................... 80,396,108 73,124,936 68,921,937 66,477,157 

Indiana ............................................................................................................. 92,010,787 83,700,336 78,901,574 76,113,835 

Iowa ................................................................................................................. 30,408,352 27,615,429 25,981,975 25,018,136 

Kansas ............................................................................................................. 26,763,719 24,295,773 22,848,095 21,990,826 

Kentucky .......................................................................................................... 76,757,356 69,698,851 65,566,898 63,126,121 

Lands of the Fort Mojave Tribe ....................................................................... 636,876 600,334 588,596 588,519 

Lands of the Navajo Nation ............................................................................. 26,449,393 23,999,556 22,557,749 21,700,587 

Lands of the Uintah and Ouray Reservation ................................................... 2,758,744 2,503,220 2,352,835 2,263,431 

Louisiana .......................................................................................................... 42,035,202 38,461,163 36,496,707 35,427,023 

Maine ............................................................................................................... 2,251,173 2,119,865 2,076,179 2,073,942 

Maryland .......................................................................................................... 17,447,354 15,842,485 14,902,826 14,347,628 

Massachusetts ................................................................................................. 13,360,735 12,511,985 12,181,628 12,104,747 

Michigan ........................................................................................................... 56,854,256 51,893,556 49,106,884 47,544,064 

Minnesota ........................................................................................................ 27,303,150 24,868,570 23,476,788 22,678,368 

Mississippi ........................................................................................................ 28,940,675 26,790,683 25,756,215 25,304,337 

Missouri ............................................................................................................ 67,312,915 61,158,279 57,570,942 55,462,884 

Montana ........................................................................................................... 13,776,601 12,500,563 11,749,574 11,303,107 

Nebraska .......................................................................................................... 22,246,365 20,192,820 18,987,285 18,272,739 

Nevada ............................................................................................................. 15,076,534 14,072,636 13,652,612 13,523,584 

New Hampshire ............................................................................................... 4,461,569 4,162,981 4,037,142 3,997,579 

New Jersey ...................................................................................................... 18,241,502 17,107,548 16,681,949 16,599,745 

New Mexico * ................................................................................................... 14,789,981 13,514,670 12,805,266 12,412,602 

New York ......................................................................................................... 35,493,488 32,932,763 31,741,940 31,257,429 

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 

* Excludes EGUs located in Indian country within the state. 

C. Compliance Timing and Allowance 

Banking 

The EPA proposes to evaluate 

compliance (i.e., compare emissions 

from affected EGUs to allowances held 

by facilities) in multi-year periods. A 

multi-year compliance period provides 

greater flexibility to affected EGUs and 

reduces administrative burden, 

compared to a single-year compliance 

period. The EPA seeks to strike a 

reasonable balance between providing 

flexibility and reducing burden while 

assuring that any noncompliance can be 

addressed in a timely fashion. 

The compliance periods in the 

proposed mass-based trading program 

would be the same as promulgated in 

the Clean Power Plan EGs, i.e., the 

Interim Period would be divided into 

three compliance periods: A 3-year 

compliance period (2022 through 2024), 

a second 3-year compliance period 

(2025 through 2027), and then a 2-year 

compliance period (2028 and 2029), for 

the Interim Period. As in the EGs, the 

Final Period would be divided into 

successive 2-year compliance periods 

commencing in 2030. The EPA would 

evaluate compliance only after the end 

of a compliance period in the massbased trading federal plan, e.g., if a 

compliance period is 3 years long, the 

agency would evaluate compliance only 

after the end of the third year in the 

period. The EPA is not reopening for 

comment the compliance periods 

promulgated in the Clean Power Plan 

EGs. 

Some existing GHG mass-based 

trading programs (i.e., emissions budget 

trading programs) use multi-year 

compliance periods. The RGGI uses 3- 

year compliance periods, along with 

intervening compliance requirements. 

The RGGI intervening compliance 

requirement is that sources must hold 

allowances to cover 50 percent of 

emissions for the first two calendar 

years of each 3-year compliance period; 

at the end of each 3-year compliance 

period sources must hold allowances to 

cover 100 percent of emissions for the 

period and allowances already deducted 

for the intervening requirement are 

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90RGGI, Summary of RGGI Model Rule changes: 

February 2013. http://www.rggi.org/docs/

ProgramReview/_FinalProgramReviewMaterials/

Model_Rule_Summary.pdf Accessed June 9, 2015. 

91Overview of ARB Emissions Trading Program. 

http://www.arb.ca.gov/cc/capandtrade/guidance/

cap_trade_overview.pdf. Accessed June 9, 2015. 

92The ‘‘allowance transfer deadline’’ is the 

deadline for transferring allowances that can be 

used for compliance in the previous compliance 

period to a source’s compliance account. For further 

information see section V.G of this preamble. 

subtracted from the 3-year obligation.90

The California Air Resources Board 

(CARB) Cap-and-Trade Program also 

uses 3-year compliance periods, along 

with intervening compliance 

requirements. The CARB intervening 

requirement is to evaluate compliance 

on 30 percent of each source’s previous 

year’s emissions every year, and 

evaluate compliance for the remainder 

of emissions every 3 years.91 The EPA 

proposes to evaluate compliance after 

each multi-year compliance period and 

is not proposing to implement 

intervening compliance requirements 

such as those in the RGGI or CARB 

programs, however, the agency requests 

comment on the inclusion of such 

requirements. 

The EPA recognizes that the 

compliance periods provided for in this 

rulemaking are longer than those 

historically and typically specified in 

CAA rulemakings. As reflected in longstanding CAA precedent, ‘‘[t]he time 

over which [the compliance standards] 

extend should be as short term as 

possible and should generally not 

exceed one month.’’ See e.g., June 13, 

1989 Guidance on Limiting Potential to 

Emit in New Source Permitting and 

January 25, 1995 Guidance on 

Enforceability Requirements for 

Limiting Potential to Emit through SIP 

and § 112 Rules and General Permits. 

The EPA determined that the longer 

compliance periods provided for in this 

rulemaking are acceptable in the context 

of this specific rulemaking because of 

the unique characteristics of this 

rulemaking, including that CO2 is longlived in the atmosphere, and this 

rulemaking is focused on performance 

standards related to those long-term 

impacts. 

The EPA proposes that allowances 

may be banked for use in any future 

compliance period, with no restriction 

on the use of banked allowances, 

including from the Interim Period (2022 

through 2029) into the Final Period 

(2030 and thereafter). The agency 

requests comment on the proposal to 

provide for unlimited allowance 

banking including the banking of 

Interim-Period allowances for use 

during the Final Period. 

Allowance ‘‘borrowing’’ is a type of 

timing flexibility wherein allowances 

from a future compliance period may be 

‘‘brought forward’’ and used for 

compliance in an earlier compliance 

period (thus reducing the amount of 

allowances available for the future 

period). The EPA notes that the 

proposed multi-year compliance periods 

inherently provide the flexibility to emit 

at relatively higher amounts in earlier 

years of a given compliance period by 

using allowances from future years 

within each compliance period (e.g., if 

the first 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 massbased trading federal plans; however the 

agency requests comment on the use of 

borrowing across compliance periods. 

Allowance borrowing across 

compliance periods would increase the 

complexity of the proposed mass-based 

trading program and reduce the 

flexibility for states to replace the 

federal plan with an approved state 

plan. First, in order for borrowing to 

occur, the EPA would have to make 

allowances from future compliance 

periods available early so that sources 

could use these future allowances in 

earlier compliance periods. The EPA 

proposes to record allowances in source 

accounts for one compliance period at a 

time in order to maximize the 

opportunities for a state to replace the 

federal plan (or replace the allowancedistribution provisions of the federal 

plan) with an approved state plan (or 

approved state allowance-distribution 

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 allowancedistribution methodology) for a 

compliance period for which the agency 

has not yet recorded allowances in 

source accounts. Recording allowances 

for multiple compliance periods at 

once—in order to make future-period 

allowances available for borrowing— 

would therefore limit these 

opportunities for states to take over 

implementation (or implementation of 

the allowance-distribution). 

If allowance borrowing from a future 

compliance period were allowed, and 

the EPA provided the opportunity for a 

state to replace the federal plan for a 

year for which allowances had already 

been borrowed and retired for 

compliance in an earlier period, those 

borrowed allowances would constitute 

additional emissions beyond the levels 

specified in the Clean Power Plan EGs. 

In that event, the EPA would then need 

to address whether and how to remove 

allowances from circulation to prevent 

inflation of the allowable emissions at 

affected EGUs in the remaining states 

subject to the federal plans (to ‘‘repay’’ 

the borrowed allowances). To avoid 

disruption to sources already subject to 

the mass-based trading federal plan, the 

EPA is not proposing to allow allowance 

borrowing across compliance periods. 

Although not proposing to provide for 

allowance borrowing across compliance 

periods, the agency requests comment 

on the potential inclusion of allowance 

borrowing in the proposed mass-based 

trading federal plans, including from 

how far into the future to allow 

allowances to be borrowed, how 

inclusion of borrowing would affect 

opportunities for states to take over 

implementation of the EGs (or 

implementation of the allowancedistribution provisions in the massbased trading federal plan), how to 

address removing the extra allowances 

from circulation that would result if 

borrowed allowances originate in a state 

that subsequently withdraws from the 

mass-based trading program, and on 

other complexities that borrowing 

across compliance periods would 

introduce. 

The agency proposes to require 

sources to demonstrate compliance, i.e., 

allowance true-up, on May 1 of the year 

after the last year in the compliance 

period. For example, if the first 

compliance period comprises the three 

years 2022, 2023, and 2024, then the 

allowance transfer deadline 92 for that 

first compliance period (after which 

point the EPA would evaluate 

compliance) would be on May 1, 2025. 

The agency also requests comment on 

an earlier or later allowance transfer 

deadline. 

The EPA proposes to evaluate 

compliance (i.e., allowance true-up) at 

the facility level, not at the individual 

affected-EGU level, in the mass-based 

trading program. Facility-level 

compliance may ease implementation 

compared to unit-level compliance; 

each facility has a single compliance 

account in which to hold allowances to 

cover emissions from all its affected 

EGUs rather than having individual 

unit-level compliance accounts. Fewer 

accounts may make it easier for the 

designated representatives to manage 

their allowances. The EPA has adopted 

facility-level compliance in previous 

emissions budget-trading programs 

including the ARP, see 70 FR 25162, at 

25296–98 (May 12, 2005); the CAIR FIP, 

see 71 FR 25328, at 25365 (April 28, 

2006); and the CSAPR, see 75 FR 45210, 

at 45323 (August 2, 2010). The EPA 

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93As detailed in section V.E in this preamble, we 

propose that a state that chooses to determine its 

own allowance-distribution approach under the 

proposed federal plan must address leakage through 

its allocation strategy (such as the set-aside 

approaches in section V.D.3 of this preamble). We 

request comment on whether a state may make a 

justification regarding leakage as detailed in section 

V.E of this preamble. 

would continue to track unit-level 

emissions—while evaluating 

compliance at the facility level— 

allowing us to track increases and 

decreases of pollutants at individual 

EGUs. 

D. Initial Distribution of Allowances 

Establishing a mass-based trading 

program requires that policymakers 

establish an approach for the initial 

distribution of allowances, historically 

referred to as ‘‘allowance allocation.’’ 

The EPA believes that states may be 

well positioned to design their own 

allowance distribution approach 

because they can take into account a 

wide range of considerations and tailor 

decisions to the particular 

characteristics and preferences of their 

state. The EPA proposes that states have 

the flexibility to determine their own 

approach for distributing allowances in 

the federal plan, through a process that 

is detailed in section V.E of this 

preamble. The EPA believes that states 

should have the opportunity to make 

decisions about allowance distribution 

and that they may have additional 

flexibility on approaches, including 

allowance auctions. The EPA is also 

proposing an allocation approach that 

we intend to use in the event we 

implement the federal plan in a state 

that does not choose to determine its 

own allowance-distribution approach. 

The EPA requests comment on all of 

these, and any other, approaches to 

distribute allowances. 

The initial allowance allocation 

approach that is based on historical data 

does not affect the environmental 

results of the program or generation 

patterns; regardless of the manner in 

which allowances are initially 

distributed, the finite total number of 

allowances limits allowable emissions 

across all affected EGUs. Allowance 

allocations also are not intended to 

prescribe or suggest any unit-level 

compliance requirements nor do they 

limit unit-level operational flexibility, 

because a mass-based trading program 

provides operators of affected EGUs 

with the flexibility to buy, sell, or bank 

allowances. Allowance allocation is 

simply a procedure by which 

allowances are distributed into the 

marketplace so that they may be 

available for affected EGUs to acquire as 

desired to authorize emissions under 

the program. However, because these 

allowances are finite in number and 

thus a limited resource, they have value, 

and as a result, initial allowance 

allocations may raise issues of equity 

among recipients. 

Thus the agency recognizes that its 

choice of allocation methodology is 

important from the perspective of 

distributional effects, and the 

importance of selecting an approach 

that is fair and reasonable in light of this 

consideration and the overall purpose of 

CAA section 111 informs the agency’s 

thinking in this proposal. We also invite 

comment on these considerations, and 

on any other factors or considerations 

which commenters believe should 

inform the allocation method. 

The EPA believes that the most 

reasonable basis for an initial allowance 

allocation procedure is an approach that 

uses historical data reported by the 

affected EGUs subject to the 

requirement to hold allowances under 

this program. This approach relies on 

known data rather than future 

projections. The EPA believes this 

approach is preferable because any 

approach tied to future indicators (e.g., 

the expected future EGU-level pattern of 

emissions or the ultimate use of 

allowances) would depend on future 

outcomes that the EPA cannot project 

with perfect certainty in advance. 

Basing allocation on historical data is 

also consistent with the EPA’s approach 

to initial allowance allocation under 

previously established mass-based 

trading programs. 

The EPA proposes to allocate most 

CO2 emission allowances to existing 

affected EGUs in each state covered by 

a final mass-based trading federal plan, 

with set-asides for a portion of 

allowances (discussed in more detail 

below). For each compliance period, the 

agency would distribute CO2 allowances 

in each covered state in the amount of 

the state’s CO2 ‘‘mass goal’’ (i.e., the 

state’s CO2 statewide mass-based 

emission goal as promulgated in the 

Clean Power Plan EGs) for that 

compliance period. For example, if a 

compliance period is 3 years long, the 

EPA would aggregate and distribute 

allowances for all 3 years at the same 

time. The agency is not proposing to 

allocate allowances to new EGUs, which 

do not have a compliance obligation 

under this proposed federal plan. For 

each year of the program, the agency 

proposes to allocate most of the 

allowances directly to affected EGUs 

using a historical-generation-based 

approach. The EPA is also proposing 

three set-asides of allowances, which 

are detailed below. 

Although the EPA cannot anticipate 

the future EGU-level pattern of 

emissions, it is possible to consider 

potential future emission patterns at the 

source subcategory level. In developing 

the Clean Power Plan EGs, the agency 

conducted analysis of emission 

reduction potential in the two affected 

EGU source subcategories, i.e., electric 

utility steam generating units (steam 

generating units) and NGCC units. With 

that analysis as a basis, the EPA requests 

comment on an alternative allocation 

approach that would first divide the 

total number of allowances from each 

state’s mass goal into source 

subcategories based on analysis done in 

developing the source category-specific 

CO2 emissions performance rates 

promulgated in the EGs and then 

allocate to affected EGUs within each 

category based on shares of historical 

generation. This alternative is described 

later in this section. 

The EPA recognizes that states may 

prefer different approaches to distribute 

CO2 allowances from the EPA’s 

approach and that there may be 

advantages in having states tailor and 

apply their own allocation approach. 

Therefore, the agency is proposing that 

a state may choose to replace the federal 

plan allowance-distribution provisions 

with its own allowance-distribution 

provisions, using any approach to 

distribute allowances that the state 

chooses, including methods that the 

EPA is not proposing here, provided 

that the state’s approach addresses 

emissions leakage and includes a Clean 

Energy Incentive Program. The 

proposed requirements for addressing 

leakage, as well as how the EPA 

proposes to implement the Clean Energy 

Incentive Program for the mass-based 

federal plan, are detailed in sections V.E 

and V.D.4 of this preamble, 

respectively.93 The EPA proposes that a 

state could choose its own method for 

distributing allowances for any 

compliance period including the first 

period that would commence in 2022. 

The proposed process for a state to 

replace federal plan allowancedistribution provisions with its own 

allowance-distribution provisions is 

detailed in section V.E of this preamble. 

The following sections discuss and 

request comment on the EPA’s proposed 

approach to allocate CO2 allowances to 

affected EGUs based on shares of 

historical generation, the proposed 

timing of allowance recordation, three 

proposed allowance set-asides, 

allocations to units that change status, 

and the proposed approach for states to 

replace federal plan allocation 

provisions with their own allowancedistribution approaches. In addition, we 

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94 In the first compliance period this would be the 

mass goal minus the Clean Energy Incentive 

Program set-aside and the RE set-aside. In all other 

compliance periods this would be the mass goal 

minus the output-based allocation set-aside and the 

RE set-aside. 

95The 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 goalsetting 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. 

request comment on alternative 

allowance distribution approaches— 

such as auctioning or allocations to 

load-serving entities—that the EPA or 

states might adopt. The EPA requests 

comment on all of these aspects of 

allowance distribution. 

1. Proposed Allocation Approach and 

Alternatives 

The EPA proposes to allocate most of 

the CO2 allowances in the mass-based 

trading program to affected EGUs based 

on historical generation (output) data. 

The EPA also proposes three allowance 

set-asides. The first would set aside a 

portion of allowances in each state from 

the first compliance period only; this 

set-aside is for a proposed Clean Energy 

Incentive Program that is detailed in 

section V.D.4 of this preamble. The 

second would set aside a portion of 

allowances in each compliance period 

except for the first period; the EPA 

proposes to distribute allowances from 

this set-aside to affected EGUs via an 

updating output-based approach as 

detailed in section V.D.3 of this 

preamble). The third would set aside 5 

percent of allowances in each state, in 

all compliance periods, to be distributed 

to RE projects as detailed in section 

V.D.3 of this preamble. In summary, the 

proposed set-asides include: 

(1) Clean Energy Incentive Program. This 

set-aside would be of first compliance period 

allowances only. 

(2) Output-based allocation set-aside. This 

set-aside would start in the second 

compliance period and continue for each 

compliance period. 

(3) Renewable energy set-aside. This setaside would be implemented in all 

compliance periods. 

This section describes the proposed 

historical-generation-based approach 

that the agency would use to allocate all 

allowances except for the set-aside 

allowances. The EPA is proposing 

affected-EGU-level allocations (based on 

available data) in every state. Further 

detail on this proposed allocation 

approach is provided in the Allowance 

Allocation Proposed Rule TSD in the 

docket. The affected-EGU-level 

allocations resulting from this proposed 

historical-generation-based approach are 

provided in the docket in an appendix 

to the TSD. The agency requests 

comment on the proposed historicalgeneration-based allocation approach 

and on other allocation approaches. 

The EPA proposes to allocate the 

historical-generation-based portion of 

the allowances (i.e., the mass goal minus 

the set-asides) 94 to individual affected 

EGUs based on each affected EGU’s 

share of the state’s historical generation, 

using 2010 through 2012 data. The 

calculation steps for this proposed 

historical-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 

historical period of 2010 through 2012 

(reflecting affected-EGU-specific 

generation assumptions incorporated in 

the data adjustments, e.g., assumed 

capacity factor for ‘‘under construction’’ 

units). For a year for which an affected 

EGU has no generation data (e.g., a year 

before the year when a unit started 

operating), assign the affected EGU a 

value of zero.95 (See step 2, below, for 

how zero values would be treated in the 

calculations.) 

The EPA proposes to use a 3-year 

historical period (i.e., 2010 through 

2012) to reflect unit-level operations 

over time. In the Clean Power Plan EGs, 

the EPA identified a reasonable basis for 

using aggregate data at the regional level 

largely based on the most recent data 

year (in that case, 2012) to inform the 

establishment of category-wide EGs (as 

opposed to individual, unit-specific 

parameters). As a distinct matter, in this 

context the EPA is considering data at 

the unit level to inform unit-specific 

initial allowance allocations; 

notwithstanding that these allowance 

allocations do not impose any unit-level 

compliance requirements in and of 

themselves, the EPA finds it reasonable 

to consider a multi-year data period to 

inform unit-level initial allocations in 

order to consider a broader range of 

unit-specific operations over time. 

(2) Determine each affected EGU’s 

average generation value by averaging 

all (non-zero) 2010 through 2012 annual 

generation values for the unit. The 

proposed approach would use only nonzero 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 historical 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 

historical data set but retire before the 

start of the program. 

(3) In each state, sum the average 

generation values from all affected EGUs 

to obtain that state’s ‘‘total average 

historical generation.’’ 

(4) Divide each affected EGU’s average 

generation value by the state’s total 

average historical generation to 

determine that affected EGU’s share of 

the state’s total average historical 

generation. 

(5) Multiply each affected EGU’s share 

of the state’s total average historical 

generation by the historical-generationallocation portion of the state’s mass 

goal (i.e., the state’s mass goal minus the 

set-asides) to determine that affected 

EGU’s allocation. 

The agency believes that this 

proposed historical-generation-based 

allocation approach is a reasonable 

approach for several reasons: 

• The agency believes that the 

proposed historical-generation-based 

approach maximizes transparency and 

clarity of allowance allocations. The 

EPA has placed in the docket the 

historical generation data and the 

calculations used to determine the 

proposed affected-EGU-level 

allocations. The agency also placed the 

proposed affected-EGU-level 

allocations, resulting from these 

calculations, into the docket. These 

calculations can be relatively easily 

replicated. 

• To calculate allocations, the EPA 

proposes to use historical affected-EGUlevel net generation data compiled using 

a methodology similar to the Emissions 

& Generation Resource Integrated 

Database methodology. The proposed 

calculation approach is described 

further below and in the Allowance 

Allocation Proposed Rule TSD in the 

docket. The historical-data methodology 

is described in the CO2 Emission 

Performance Rate and Goal 

Computation TSD for Clean Power Plan 

Final Rule. The majority of the 

generation-unit-level data in this 

approach are from reports that 

emissions sources submit to the EPA 

under 40 CFR part 75 and to the EIA on 

forms EIA–860 and EIA–923. The EPA 

believes these are the best data available 

to the agency at the time of this 

proposed rule for calculating affectedEGU-level allocations. 

• Allocating based on historical data 

(as opposed to data not yet reported) 

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allows for the distribution of allowances 

prior to the start of the program, which 

can facilitate compliance planning. 

The proposed approach is 

transparent, based on reliable data, and, 

like the approaches used in the NOX SIP 

Call, the ARP, and CSAPR, based on 

historical data. For all these reasons, the 

agency believes that it is appropriate to 

use a historical-generation-based 

allocation methodology in this proposed 

rule. The EPA also requests comment on 

a historical-data approach based on 

historical emissions. 

The proposed historical-data-based 

allocations approach would not 

generally affect the ultimate pattern of 

generation across individual power 

plants, as compared to other methods of 

allocation. The combination of plants, 

and their contributing generation, that 

will be used to meet a particular 

demand for electric power will be based 

on the relative efficiency (cost of 

production) of available plants. The 

relevant measure of this efficiency is the 

marginal cost of generation, which for a 

particular power plant would be the 

sum of the cost of additional fuel to 

generate an additional MWh, additional 

maintenance costs to increase output by 

an additional MWh, and costs 

associated with the additional emissions 

that result from generating an additional 

MWh. In a mass-based trading program, 

additional emissions must be covered 

by additional allowances, so the cost of 

emitting is the price of the allowances 

that must be consumed to authorize 

those emissions. These emissionsrelated costs of electricity production 

are the same regardless of whether the 

allowances used to cover those 

emissions were initially allocated to the 

user or whether they were acquired 

subsequently in the marketplace. 

The same concept applies to any other 

cost of electricity production. For 

example, a coal-fired EGUs operator 

would account for the cost of 

consuming coal to produce generation 

whether or not the coal was discovered 

already on-site, given to the unit at ‘‘no 

charge’’, or purchased from the 

marketplace; in all cases, the 

combustion of that coal consumes its 

value (i.e., it can no longer be sold). 

Similarly, the approach taken to 

distribute allowances does not affect the 

cost accounting for emissions at units 

because the use of any tradable 

allowance has an opportunity cost—a 

firm loses the opportunity of selling an 

unneeded allowance when it emits an 

additional ton. Because a firm loses the 

opportunity of selling an unneeded 

allowance when it emits an additional 

ton, even the emission of a ton covered 

by a ‘‘free’’ allowance causes the 

generator to incur the cost of emissions 

based on the market price of allowances 

the owner must forgo by emitting that 

ton and using that allowance. 

The proposed historical-data-based 

allocation approach would not be 

expected to have any effect on freely 

competitive electricity markets, because 

the marginal cost of emitting under the 

mass-based trading program is 

determined by the level of the 

overarching mass goals and is not 

affected by the distribution of the 

underlying allowances. This marginal 

cost of emitting is what will inform 

prices, outputs, and competition among 

power plants. While cost-of-service 

markets are structured differently from 

competitive markets, the regulated 

utility still makes the dispatch decision 

on the basis of marginal costs among the 

units in its fleet, which is not affected 

by the amount of allowances that any 

particular unit in that fleet was initially 

allocated (assuming a competitive 

allowance market). 

The EPA recognizes that some 

stakeholders are concerned about the 

potential future distribution of 

emissions at the facility level, and 

possible effects on communities. 

However, for the reasons discussed in 

the above paragraphs, allowance 

allocations that do not change based on 

future activity (such as allocations 

under the proposed historicalgeneration-based approach) do not affect 

the distribution of emissions under the 

program. This proposed rule is expected 

to achieve significant emission 

reductions across the electric power 

sector; see section IX of this preamble 

for discussion of anticipated broad 

benefits to communities. 

In addition to the proposed historicaldata-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 historical generation. 

However, this alternative approach 

would divide the total number of 

allowances from a state’s mass goal 

(minus the set-asides) into affected EGU 

source categories—based on analysis 

done in developing the source categoryspecific 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 

source-category level to the future 

category-level pattern of emissions, and 

thus to allowances ultimately used, than 

the proposed approach. To the extent 

that this category-level division of 

allowances is a reasonable proxy for the 

future category-level emissions pattern 

under the program, this approach may 

reduce wealth transfer between parties 

that occurs as a consequence of a lessanticipatory 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 historical 

steam-generating-unit generation by the 

steam-generating-unit source categoryspecific CO2 emissions performance 

rate, and multiply historical NGCC-unit 

generation by the NGCC-unit source 

category-specific CO2 emissions 

performance rate. The EPA would do 

these calculations for each of the 

compliance periods in the Interim 

Period using the glide path interim 

performance rates, and for the Final 

Period using the final performance rates. 

These performance rates are shown in 

Table 6 in section IV.B of this preamble, 

above. The EPA established the source 

category-specific emissions performance 

rates in the Clean Power Plan EGs (see 

section VI of the final EGs); these rates 

are not within the scope of this 

proposed federal plan rulemaking. Next, 

for each compliance period the EPA 

would split the total number of 

allowances from the state’s mass goal 

(minus the set-asides) into affected-EGU 

source categories in proportion to the 

values resulting from the above 

calculation. The EPA would then 

allocate the steam-generating-unit 

portion of the allowances to individual 

SGUs using the same historicalgeneration-based approach described 

above, and would also allocate the 

NGCC-unit portion of the allowances to 

individual NGCC units using the 

historical-generation-based approach. 

The EPA notes that there are multiple 

approaches that policymakers may use 

to distribute allowances, beyond the 

proposed or alternative allocation 

approaches we included in this 

proposed rule. Examples of other 

allocation approaches include allocating 

based on historical heat input (fuel) or 

historical emissions data, rather than 

historical generation data. The choice to 

use historical 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 

historical emissions would benefit those 

that have historically been the largest 

emitters, whereas allocations based on 

historical heat input or generation 

(output) would benefit those that have 

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96Tools of the Trade, A Guide to Designing and 

Operating a Cap and Trade Program for Pollution 

Control, EPA, 2003. 

97The EPA believes authority to conduct auctions 

is located in CAA section 111 alone, as well as by 

its reference to CAA section 110(c) FIPs. The 

statutory definition of a FIP authorizes ‘‘techniques 

(including economic incentives, such as marketable 

permits or auctions of emissions allowances).’’ 42 

U.S.C. 7602(y). 

historically used the most fuel or 

generated the most electricity.96

Alternatively, allocations could be 

distributed based on projected or 

observed future activity (e.g., 

generation, heat input, or emissions). 

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 outputbased approach as detailed in section 

V.D.3 of this preamble. The EPA 

requests comment on the use of other 

updating allocation approaches. 

Another allowance allocation 

approach that could minimize the 

difference between the initial allowance 

allocation and the ultimate 

distributional pattern of allowance use 

for compliance is to conduct an auction, 

a process whose express intent is to 

align the allocation of a scarce good (in 

this case, the limited authorization to 

emit CO2) with the parties most willing 

to pay for its use. Many ascribe benefits, 

in terms of economic efficiency, to the 

use of auctioning as a means of 

allocating allowances. The EPA notes 

that some states (e.g., RGGI participating 

states) have used auctions to distribute 

allowances and have used auction 

revenues for a variety of purposes, 

including the implementation of 

demand-side EE measures intended to 

help reduce electricity rate impacts and 

overall program costs, as well as 

targeted investments in low-income 

communities. The EPA believes that if 

it conducted allowance auctions, any 

revenue from such auctions received by 

the agency must be deposited in the 

U.S. Treasury under federal law.97 As a 

result, the EPA notes that states 

implementing state plans may have 

greater flexibility than the federal 

government would to direct auction 

funds for particular activities. The 

agency requests comment on the idea of 

auctioning all, or a portion of, each 

state’s allowances in the proposed 

federal plan, on how much of each 

state’s allowances to auction if not the 

entire amount, on the frequency (e.g., 

yearly or every few years), design of 

auctions (e.g., spot or advance; first, 

second-price or other) and who may 

participate in the auction. 

The EPA requests comment on an 

alternative approach, which is 

allocating a portion of the allowances to 

load-serving entities (LSEs) rather than 

to affected EGUs. LSEs are the entities 

responsible for delivering power to 

retail consumers. 

Allocation to LSEs can help mitigate 

bill impacts on electricity consumers 

when applied in concert with certain 

additional design features. In particular, 

if LSEs commit and/or are required to 

pass through to ratepayers the value 

from their selling of the allocated 

allowances, this approach can mitigate 

the impact of electricity bill increases 

on consumers that might otherwise 

result from application of the federal 

plan. As described in the Allowance 

Allocation TSD, this type of approach 

can also help to avoid or mitigate the 

potential for windfall profits for affected 

EGUs. The EPA could apply this 

approach by conditioning the receipt of 

allowances by LSEs on the pass through 

to consumers of any allowance value if 

necessary. 

The EPA requests comment on the 

design and utility of allocating 

allowances to LSEs to help mitigate 

electricity price impacts. In particular, 

the EPA requests comment on options to 

establish conditions requiring pass 

through of allowance value and 

verification of such pass-through, 

whether it would be appropriate to 

identify any conditions related to 

equitable distribution of allowance 

value among ratepayer categories, as 

well as the EPA’s legal authority to 

apply any such conditions. 

The EPA requests comment on the 

additional design aspects of any 

potential allocation to LSEs, including 

but not limited to the following 

questions: In particular, what metric 

should provide the basis for LSE 

allocation, e.g., electricity demand 

served by the LSE, population served by 

the LSE, emissions associated with 

generation serving the LSE, or some 

other metric. If emissions are used as 

the basis for such allocation, what 

approach should be taken: On a 

historical basis or a continually updated 

basis, on the basis of estimated 

emissions for the relevant region or 

some other basis, and using what data 

to calculate such emissions. Also, the 

EPA requests comment on the form by 

which LSEs may distribute the 

allowance value to rate-payers, e.g. as a 

fixed amount, through reduced rates, 

etc. Finally, the EPA requests comment 

on what share of the total number of 

allowances should be distributed to 

LSEs and what monitoring and 

reporting requirements may be 

necessary to support an effective 

program. 

The EPA also requests comment on 

the proposed historical-generationbased allocation approach, the 

alternative approach that divides total 

allowances from a mass goal into source 

subcategories before allocating to 

individual affected EGUs within each 

source category based on historical 

generation, and on the other alternative 

approaches described in this section. 

The EPA also requests comment on 

allocating allowances to all generation 

in a state (including non-emitting 

generation) using a historicalgeneration-based approach. The agency 

also requests comment on the proposed 

allowance set-asides, which are detailed 

below. The agency requests comment on 

allocation approaches that may 

minimize the impact of this proposed 

rule on small entities. The EPA also 

requests comment on any other 

approaches to distribute allowances. 

The agency notes that we propose to 

provide that any state may choose to 

replace the federal plan allocation 

provisions with an allocation approach 

of its choosing as discussed below. 

Finally, with regard to alternative 

allocation methodologies (either those 

specifically mentioned in this proposal 

or other allocation methodologies), the 

EPA requests comment on how those 

alternatives would satisfy the 

requirement that in a mass-based 

program where new sources are not 

included as part of the program, the 

allocation methodology must address 

leakage to new fossil fuel-fired sources. 

2. Timing of Allowance Recordation 

The proposed historical-data-based 

allocation approach—which the EPA 

proposes to use to allocate all of the 

allowances in each state except for the 

set-aside allowances—is a 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 historical-data-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. 

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98The EPA is also proposing a third set-aside, for 

a Clean Energy Incentive Program, which is detailed 

in section V.D.4 of this preamble, below. 

99 In designing a federal plan under CAA section 

111(d), the EPA recognizes its authority as being, 

in some sense, the same as that available under 

CAA section 110(c), where the use of economic 

incentives is authorized. See CAA section 302(y), 

42 U.S.C. 7602(y) (authorizing use of ‘‘economic 

incentives’’ in FIPs). 

100See also EPA, Allowance Allocation Final 

Rule TSD, EPA–HQ–OAR–2009–0491, at 3–4 (June 

2011). 

Recording allowances for one 

compliance period at a time provides 

flexibility for a state to replace the 

federal plan with its own plan in a 

timely way. As discussed in section V.F 

of this preamble, the EPA proposes to 

allow a state to replace the federal plan 

with its own approved state plan, for a 

compliance period for which 

allowances have not yet been recorded 

(the proposed schedule for allowance 

recordation is detailed below). The EPA 

also proposes that a state could choose 

to replace the federal plan allocations to 

its affected EGUs (and other entities) 

with its own allocations approach, for a 

compliance period for which 

allowances have not yet been recorded 

as detailed in section V.E of this 

preamble. 

The agency proposes to record 

allowances for the mass-based trading 

program in accounts of affected EGUs 7 

months prior to the start of each 

compliance period. For example, if 

compliance periods are 3 years long and 

the first compliance period comprises 

the years 2022, 2023, and 2024, the EPA 

would record allowances for 2022, 2023, 

and 2024 by June 1, 2021. The EPA 

requests comment on the proposed 

approach of recording allowances 7 

months prior to the start of each 

compliance period, and on an 

alternative of recording allowances 13 

months prior to the start of each 

compliance period. See section V.D.3 of 

this preamble for timing of recordation 

of allowances from the proposed 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 massbased federal plan. These two set-asides 

are being proposed to satisfy the 

requirement in the final guidelines that 

mass-based plans demonstrate that they 

have addressed the risk of leakage to 

new unaffected units, as specified 

below.98

The final EGs specify the concern of 

leakage, which is defined in section 

VII.D of the final EGs preamble as the 

potential of an alternative form of 

implementation of the BSER (e.g., the 

rate-based and mass-based state goals) to 

create a larger incentive for affected 

EGUs to shift generation to new fossil 

fuel-fired EGUs relative to what would 

occur when the implementation of the 

BSER took the form of standards of 

performance incorporating the 

subcategory-specific emission 

performance rates representing the 

BSER. The final EGs specified that 

mass-based plan approaches must 

address leakage, because the form of the 

mass goals may ultimately impact the 

relative incentives to generate and emit 

at affected EGUs as opposed to shifting 

generation to new sources, with 

potential implications for whether the 

mass goal implements or is consistent 

with the BSER and overall emissions 

from the sector. These circumstances are 

much less likely to be present under a 

rate-based plan approach, where the 

form of the goal ensures sufficient 

incentive to affected existing EGUs to 

generate and thus avoid leakage, similar 

to the CO2 emission performance rates. 

By requiring mass-based plan 

components that address leakage, the 

final EGs ensure that mass goals are 

equivalent to the CO2 emission 

performance rates and are thus an 

equivalent expression of the BSER. 

Section VII.D of the final EGs details the 

requirement for addressing leakage and 

why it is needed, and section VIII.J of 

the final EGs specifies options for massbased state plan components that 

address leakage. We are proposing, as 

part of the mass-based approach under 

the federal plan and model rule, to 

implement allowance allocation 

approaches to address leakage, 

specifically through establishing an 

output-based allocation set-aside and a 

set-aside that encourages the installation 

of RE. 

As noted in the EGs, if a state were 

to adopt allowance set-aside provisions 

exactly as they are outlined in this 

model rule once it is finalized, the 

requirement for that state plan to 

address leakage would be considered 

presumptively approvable. 

Section VIII.J of the final EGs provides 

a discussion of how set-asides can 

effectively address leakage in a massbased plan approach. That section of the 

final EGs also describes why the 

allowance allocation alternative for 

addressing leakage must be chosen for 

the federal plan 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 fuel-fired sources under 

CAA section 111(d), and therefore we 

cannot include new sources under a 

federal mass-based plan approach. 

The set-asides we are proposing— 

described in detail below—would 

establish a pool of allowances that 

would be allocated to affected EGUS or 

other entities based upon criteria 

designed to address leakage. 

These set-asides are essentially a type 

of ‘‘economic incentive’’ authorized by 

the CAA as a means of pollution 

prevention and control, and the 

expected benefits of this particular type 

of economic incentive to address 

leakage make it appropriate here.99 The 

EPA believes these set-aside programs 

are both authorized and consistent with 

the purpose of the Clean Power Plan 

under CAA section 111(d) and the 

specific requirements specified in the 

final guidelines. They do not have the 

effect of increasing the stringency of the 

federal plan because the overall budget 

of allowances (representing allowable 

emissions) remains the same. 

The EPA is aware of the successful 

use of set-asides and similar programs 

in other emissions trading programs. 

The following are examples of set-asides 

and similar programs used in other 

federal air quality rules. 

The EPA has previously established 

set-asides of emissions allowances in 

FIPs under CAA section 110. For 

example, in the CSAPR, the EPA used 

a 5 percent set-aside for new units, 

because we believed it was ‘‘important 

to have a small new unit set-aside in 

each state to cover new units within the 

budget that was set aside in order to 

address the state’s significant 

contribution and interference with 

maintenance.’’ (75 FR 45310; August 2, 

2010). This was important, in the EPA’s 

view, because it allowed for growth in 

the electric utility sector consistent with 

the EPA’s modeling, where new units 

showed up in the modeling output as 

surrogate facilities representing 

potential new EGUs that come online in 

future years in response to demand 

increases or other market drivers.100 As 

between a choice of requiring these new 

units to purchase their allowance on the 

open market, versus being treated in the 

same manner as existing—and generally 

understood to be less efficient and more 

polluting—units, i.e., by being eligible 

to receive an initial allowance allocation 

out of the new unit set-aside, the EPA 

chose the latter. 

As part of the ARP under Title IV of 

the 1990 CAA Amendments, Congress 

established a ‘‘conservation and 

renewable energy reserve’’ account. See 

CAA section 404(f), 42 U.S.C. 7651c(f). 

This is in essence a set-aside account of 

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101U.S. EPA, Acid Rain Program, Conservation 

and Renewable Energy Reserve, EPA 430–R–94–010 

(November 1994). 

102U.S. EPA, State Clean Energy-Environment 

Technical Forum Roundtable on State 

NOXAllowance EE/RE Set Aside Programs, Call 

Summary (June 6, 2006), available at http://

www.epa.gov/statelocalclimate/documents/pdf/

summary_paper_nox_allowance_6-6-2006.pdf. 

103The agency has extensive experience in the 

design and establishment of set-aside programs. 

See, e.g., Guidance on Establishing an Energy 

Efficiency and Renewable Energy (EE/RE) Set-Aside 

in the NOX Budget Trading Program (March 1999), 

available at http://www.epa.gov/statelocalclimate/

documents/pdf/ee-re_set-asides_vol1.pdf; Creating 

an EE and RE Set-aside in the NOX Budget Trading 

Program: Designing the Administrative and 

Quantitative Elements (April 2000), available at 

http://www.epa.gov/statelocalclimate/documents/

pdf/ee-re_set-asides_vol2.pdf; Creating an EE and 

RE Set-aside in the NOX Budget Trading Program: 

Evaluation, Measurement, and Verification of 

Electricity Savings for Determining Emission 

Reductions from Energy Efficiency and Renewable 

Energy Actions (July 2007), available at http://

www.epa.gov/statelocalclimate/documents/pdf/eere_set-asides_vol3.pdf. 

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 demand-side EE savings or RE 

generation. In the first years of the 

program, utilities received bonus 

allowances equivalent to close to 3,000 

tons of avoided SO2 emissions, while 

achieving co-benefits from reductions in 

other pollutants, and, in the words of 

one industry representative, ‘‘creating a 

culture change where utilities are 

looking for opportunities 

everywhere.’’ 101 The reserve program 

was nonetheless undersubscribed, and 

the EPA and other parties have learned 

from this case and made adjustments to 

similar programs to promote 

participation. This proposal seeks to 

minimize the administrative burden 

associated with participation in this 

rule’s proposed set-asides. 

In the NOX SIP Call, the EPA 

encouraged states to consider including 

energy efficiency and renewables as a 

strategy in meeting their emission 

budgets through the use of set-asides. 

See 63 FR 57356, 57438 (October 27, 

1998). A number of states created RE 

and demand-side EE set-asides in their 

SIPs in response, and later, for the 

implementation of CAIR. A 

‘‘roundtable’’ meeting with 25 states in 

2006 indicated that states that had 

established these programs were 

generally having success with them, and 

provided a forum for exchanges of ideas 

on how to handle a variety of 

implementation issues, such as overand 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

Below, the EPA describes two 

potential allowance set-asides. First, the 

EPA proposes a set-aside for allowances 

distributed to existing NGCC units 

based on output (i.e., output-based 

allocation) to mitigate emission leakage 

to new sources. Second, the EPA 

proposes a set-aside for electricity 

generation from qualifying renewables. 

This set-aside also addresses the 

potential for leakage to new sources, as 

increased RE capacity can serve 

electricity demand in place of new 

sources. The EPA also solicits comment 

on other set-aside options that could 

address leakage, including a set-aside 

that provides an incentive for demandside EE. The EPA seeks comment on all 

aspects of the set-aside options specified 

in this section. This includes the 

inclusion of a set-aside, the method for 

allocation of allowances to set-asides, 

the size of the set-asides, the 

requirements for the process of 

distribution, eligibility requirements for 

receiving set-aside allowances, the 

proposed process for redistribution of 

undistributed allowances from each setaside, and any other appropriate setasides. 

a. Set-Asides for Output-Based 

Allocation 

The EPA is proposing a set-aside 

approach referred to as output-based 

allocation, which provides targeted 

allocations of a limited portion of 

allowances to existing NGCC units as a 

means of mitigating leakage. The EPA 

believes that this proposed set-aside 

would reduce incentives for generation 

to shift away from EGUs covered under 

mass-based plans to new unaffected 

EGUs. We seek comment on all aspects 

of this proposal and its underlying 

rationale. 

Under the output-based allocation 

approach we are proposing, beginning 

with the second compliance period, a 

portion of the total allowances within 

each mass-based federal plan state 

would be allocated to existing NGCC 

units based, in part, on their level of 

electricity generation in the previous 

compliance period. Each eligible EGU 

would get a larger allowance allocation 

from this set-aside if it generates more, 

such that owner/operators of eligible 

EGUs will have an incentive to generate 

more in order to receive more 

allowances. Because the total number of 

allowances is limited, this allocation 

approach will not exceed the overall 

emission goal. Instead, it merely 

modifies the distribution of allowances 

in a manner designed to align the 

generation incentives for eligible EGUs 

in mass-based states with new emitting 

EGUs that are not subject to a massbased limit, mitigating emissions 

leakage. 

The EPA is inviting comment on key 

parameters for the appropriate design of 

the output-based allocation approach 

used for this proposed set-aside. Key 

parameters to be identified under the 

output-based allocation approach 

include which affected EGUs receive the 

allocation, the timing of the set-aside’s 

allocation procedure, the allocation 

rate(s), and the size of the set-aside. The 

EPA also invites comment on what 

other parameters may be relevant for 

design of an appropriate output-based 

set-aside. 

The EPA first solicits comment on 

which EGUs should be eligible to 

receive output-based allocation from the 

set-aside. The EPA proposes that only 

NGCC units subject to the final EGs 

receive output-based allocation from the 

set-aside. The EPA recognizes that 

performance of output-based allocation 

may be improved by targeting which 

units receive this additional incentive. 

In particular, this approach can most 

effectively address emission leakage if 

targeted to those affected EGUs subject 

to a mass goal that face the greatest 

difference in their incentive to generate 

relative to otherwise similar EGUs that 

are not subject to a mass goal. As noted 

in the discussion of the allocation rate 

below, new combustion turbines (i.e., 

NGCC units and simple cycle 

combustion turbines) would be 

expected to generate more absent this 

set-aside. Therefore, the difference in 

generation incentives between affected 

stationary combustion turbines subject 

to a mass goal and otherwise similar 

new stationary combustion turbines that 

are not subject to a mass goal is likely 

one of the most salient deviations in 

production incentives to address. 

The EPA also requests comment on 

extending output-based allocation from 

this set-aside to affected SGUs. Outputbased allocation for SGUs may increase 

generation subject to the mass limit, 

leading to reduced generation and 

emissions from new emitting sources. 

However, the EPA does not propose this 

approach because it is not as effective as 

output-based allocation to NGCC units. 

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104Effectively, the allocation rate (defined below) 

of output-based allocation is zero up until this 

average capacity factor. 

105The EPA recognizes that under this lagged 

accounting procedure, if the federal plan is replaced 

by a state plan in a future compliance period, the 

incentive to create eligible generation in the last 

compliance period subject to the federal plan is 

potentially diminished. 

106See section V.H of this preamble for proposed 

monitoring and reporting requirements. The EPA 

proposes to make the reported generation data 

available to the public on the agency’s Web site. 

107CO2 Emission Performance Rate and Goal 

Computation TSD for the Clean Power Plan Final 

Rule. 

108The sum of net summer capacity for affected 

NGCC units in the 2012 baseline for the Clean 

Power Plan EGs (CO2 Emission Performance Rate 

and Goal Computation TSD for the Clean Power 

Plan Final Rule). 

This is because output-based allocation 

to SGUs would incentivize generation 

from relatively high-emitting EGUs, 

which would likely increase allowance 

prices as other emission reductions are 

made to respect the overarching mass 

limit. This approach would thus 

strongly counteract the intended effect 

of lowering the production cost from 

sources subject to the proposed massbased federal plan (compared to 

emitting sources not subject to the plan). 

The EPA also requests comment on 

extending output-based allocation from 

this set-aside to zero-emitting generators 

(including both renewable and nuclear 

generation), and how the design of the 

OBA set-aside for such generators 

would differ relative to the NGCC 

approach (e.g., the amount of 

allowances earned per MWh, the 

capacity-factor threshold, the size of the 

total set-aside). 

The EPA also proposes that this 

approach be targeted towards marginal 

generation that may not have otherwise 

occurred absent this set-aside, by 

providing allocations under this setaside only to eligible EGUs that exceed 

a 50 percent capacity factor on a net 

basis over the compliance period, and 

only for the portion of their generation 

that exceeds that capacity factor.104

The EPA also solicits comment on the 

timing of the output-based allocation 

set-aside’s allocation procedure, which 

involves the relationship between the 

time at which eligible generation occurs 

and the vintage year(s) of the allowances 

allocated from this set-aside to 

recognize that generation. The EPA is 

proposing a lagged accounting 

procedure for this set-aside, where 

eligible generation that occurs during a 

given compliance period would receive 

allowances through this set-aside taken 

from vintage years in the subsequent 

compliance period. In keeping with this 

lagged accounting procedure, the EPA is 

proposing not to reserve any allowances 

of vintage years during the first 

compliance period (2022–2024) for 

allocation through this set-aside; eligible 

generation that occurs during the first 

compliance period would be recognized 

through this set-aside with allowances 

of vintage years from the second 

compliance period (2025–2027). 

The EPA is proposing this lagged 

accounting procedure because the 

amount and location of eligible 

generation in any given compliance 

period remains uncertain until the 

compliance period has ended and the 

relevant data has been reported and 

verified. Without this lagged accounting 

procedure, the EPA would have to 

withhold an amount of allowances for 

this set-aside from certain vintage years 

even as the corresponding compliance 

period was already underway. Given the 

size of this proposed output-based 

allocation set-aside in certain states, the 

EPA believes it would be more 

advantageous for affected EGUs to know 

in advance how many allowances they 

will be allocated in a given period, 

inclusive of allowances allocated 

through this output-based allocation setaside.105

The EPA requests comment on 

options for the allocation rate under this 

approach. The allocation rate is the 

number of allowances, in an amount 

equal to a specific amount of emissions, 

that the affected EGU receives per one 

net MWh of generation eligible for the 

set-aside. The EPA proposes to set the 

allocation rate equal to the rate-based 

emission standard (on a net basis) for 

new NGCC units under 111(b), in order 

to align the generation incentives across 

EGUs eligible for the set-aside and the 

type of new emitting source that would 

generate more absent this set-aside. 

Specifically, an additional MWh of 

eligible generation would earn the 

affected EGU allowances equal to the 

level of emissions permitted per MWh 

of net generation under the 111(b) new 

source standard, which is 1,030 lbs/

MWh-net (Carbon Pollution Standards 

for new, modified, and reconstructed 

EGUs). The EPA requests comments on 

other values for the allocation rate. For 

example the allocation rate may be the 

expected net emissions rate of newly 

constructed NGCC units, the historical 

average emissions rate from NGCC 

units, or the NGCC or fossil steam 

source category-specific emissions 

performance rates promulgated in the 

Clean Power Plan EGs (see section VI of 

the final EGs). 

The EPA proposes to calculate an 

NGCC unit’s capacity factor based on 

the previous compliance period’s net 

generation and the net summer capacity 

of the unit. The EPA is proposing to 

require affected EGUs to report net 

generation to the agency.106 The EPA 

proposes to use net summer capacity as 

reported to EIA. In the alternative, the 

EPA proposes to require that NGCC 

units report net summer capacity 

directly to the EPA by adding it as a 

required data field in the certificate of 

representation that a unit’s owner or 

operator would submit to the agency 

(see section V.G of this preamble). The 

EPA notes that the EIA net summer 

capacity data is reported at the generator 

level; if we add this data point to the 

certificate of representation it would be 

reported at the affected-EGU level, 

which would facilitate calculation of 

capacity factors. The EPA also requests 

comment on whether the ‘‘maximum 

load value,’’ which is a parameter that 

EGUs report to the EPA in their 

monitoring plans, is a reasonable proxy 

for EGU-level net summer capacity for 

these calculations. The EPA also 

requests comment on an alternative 

approach of basing the capacity-factor 

calculation on nameplate capacity 

instead of net summer capacity, or other 

approaches to the calculation. 

The EPA proposes to determine the 

size of the output-based set-aside once, 

before the start of the program, and not 

to change the size thereafter. The EPA 

proposes to determine the size of the 

set-aside assuming that it would 

incentivize existing NGCC to increase 

utilization to a 60 percent capacity 

factor. The assumed 60 percent capacity 

factor offers a way to limit the size of 

this set-aside, which allows the 

remainder of the allowances in a given 

compliance period to be allocated 

through the historical-generation 

approach (as detailed above) and the 

other proposed set-asides (as detailed 

below). Furthermore, limiting the size of 

the set-aside avoids the risk of 

incentivizing too much generation from 

eligible sources, as discussed further in 

the Allowance Allocation Proposed 

Rule TSD. 

The EPA proposes to determine the 

size of the output-based set-aside using 

2012 baseline data from the Clean 

Power Plan EGs.107 The EPA would 

calculate the size of the set-aside as 10 

percent of the NGCC capacity in the 

state 108 multiplied by the hours in a 

year multiplied by the allocation rate for 

the set-aside. The EPA requests 

comment on the proposed capacity data 

used as the basis for determining the 

size of the output-based set-aside, and 

alternative sources of capacity data that 

may be used for determining its size. 

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The set-asides resulting from this 

proposed approach are shown in Table 

9 of this preamble. The set-asides in the 

table would apply to every compliance 

period except for the first compliance 

period for which there would be no 

output-based set-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 set-aside in a compliance 

period based on a percentage of the 

state’s total allowances for the 

compliance period. 

TABLE 9—PROPOSED SIZE OF OUTPUT-BASED SET-ASIDE FOR THE

SECOND COMPLIANCE PERIOD AND

LATER

[Short tons] 

State 

Allowances in 

output-based 

set-aside 

Alabama ................................ 4,185,496 

Arizona .................................. 4,197,813 

Arkansas ............................... 2,102,538 

California ............................... 8,458,604 

Colorado ............................... 1,348,187 

Connecticut ........................... 1,090,811 

Delaware ............................... 649,190 

Florida ................................... 12,102,688 

Georgia ................................. 3,563,104 

Idaho ..................................... 246,638 

Illinois .................................... 1,598,615 

Indiana .................................. 1,106,150 

Iowa ...................................... 492,510 

Kansas .................................. 62,257 

Kentucky ............................... 288,730 

Lands of the Fort Mojave 

Tribe .................................. 248,127 

Lands of the Navajo Nation .. 0 

Lands of the Uintah and 

Ouray Reservation ............ 0 

Louisiana .............................. 2,207,879 

Maine .................................... 563,925 

Maryland ............................... 103,762 

Massachusetts ...................... 2,439,991 

Michigan ............................... 2,105,786 

Minnesota ............................. 909,724 

Mississippi ............................ 3,132,671 

Missouri ................................ 815,210 

Montana ................................ 0 

Nebraska .............................. 144,635 

Nevada ................................. 2,326,529 

New Hampshire .................... 542,721 

New Jersey ........................... 3,413,100 

New Mexico .......................... 627,085 

New York .............................. 3,815,381 

North Carolina ...................... 2,120,178 

North Dakota ........................ 0 

Ohio ...................................... 1,757,326 

Oklahoma ............................. 3,121,167 

Oregon .................................. 1,291,027 

TABLE 9—PROPOSED SIZE OF OUTPUT-BASED SET-ASIDE FOR THE

SECOND COMPLIANCE PERIOD AND

LATER—Continued 

[Short tons] 

State 

Allowances in 

output-based 

set-aside 

Pennsylvania ........................ 4,392,931 

Rhode Island ........................ 778,307 

South Carolina ...................... 1,029,366 

South Dakota ........................ 130,831 

Tennessee ............................ 632,949 

Texas .................................... 15,990,657 

Utah ...................................... 825,586 

Virginia .................................. 3,011,811 

Washington ........................... 1,383,060 

West Virginia ........................ 0 

Wisconsin ............................. 1,181,175 

Wyoming ............................... 45,114 

Given the proposed limit on the total 

size of the set-aside, and the amount of 

potential generation eligible for the setaside, there may be fewer allowances 

available in the set-aside than can be 

earned at the allocation rate. The EPA 

proposes that, if the amount of total 

generation eligible for the set-aside 

multiplied by the allocation rate 

exceeds the size of this set-aside, then 

the allowances in this set-aside would 

be allocated to eligible generation on a 

pro-rata basis. 

The EPA proposes that if the number 

of allowances allocated from the setaside is less than the size of this setaside, then the remaining allowances 

would be distributed to all affected 

EGUs using the historical-generationbased approach described above. 

The EPA proposes to provide notice 

of the capacity and generation data used 

to calculate allocations from the setaside, and the resulting allocations, by 

August 1 of the first year in each 

compliance period, e.g., by August 1, 

2025 for the compliance period that 

commences in 2025 (and based on the 

data from the prior compliance period). 

The agency proposes to provide 30 days 

for comment on the data and 

allocations, until August 31, and to 

provide notice of the final set-aside 

allocations by November 1 of the same 

year and record the allocations in the 

source accounts at that time. The EPA 

requests comment on other approaches 

to providing notice of the data and 

allocations. 

The EPA requests comment on all 

aspects of the proposed approach to 

calculate output-based set-aside 

allocations. Further details are in the 

Allowance Allocation Proposed Rule 

TSD in the docket. 

b. Set-Asides for Renewable Energy 

Projects 

The EPA proposes to provide a setaside of allowances for distribution to 

RE projects in each state covered by the 

proposed mass-based federal plan, and 

is also proposing this for the mass-based 

model rule. The agency also requests 

comment on whether distribution 

should extend to DS–EE, CHP, and other 

types of projects. Under this program, 

the EPA would reserve a percentage of 

each state’s allowances in a set-aside 

account for each state. Developers of RE 

projects could apply to receive set-aside 

allowances based on the projected 

generation from eligible RE capacity. 

This set-aside is expected to address 

concerns regarding leakage by lowering 

the marginal cost of production of the 

incented clean energy technologies 

within the state. This will make RE 

more competitive against new sources, 

reducing the potential for leakage to 

new sources. While the proposed setasides would provide additional 

incentive for the creation of additional 

RE capacity, it should also be noted that 

the proposed mass-based trading 

program itself would provide incentive 

for new and existing low and zeroemitting generation. 

In the context of the proposed federal 

plan, the EPA is proposing that it would 

create a unique set-aside for each state 

covered by a mass-based federal plan. 

Under a model rule, the state would 

create this set-aside. The allowances in 

each 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 5 percent of allowances 

will be reserved from the allocation for 

each state for the purpose of the setaside. We are also requesting comment 

on options for a percentage of 

allowances to be reserved ranging from 

1 to 10 percent of total allowances in 

each state. The proposed percentage has 

been determined to provide a 

meaningful additional incentive for RE 

activities in each state, while ensuring 

that the vast majority of allowances are 

freely allocated to affected EGUs. The 

EPA made this conclusion based upon 

determining an appropriate volume of 

set-aside resources that, at a range of 

possible allowance prices, are projected 

to incent the development of additional 

RE projects. The analysis is provided in 

the docket as part of the Renewable 

Energy Set-aside 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 

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thus the provision of these set-asides 

does not affect the overall stringency of 

the program. 

In section V.D.5 of this preamble, 

below, the EPA is proposing that the 

size of the RE set-asides may grow over 

time as certain units shift out of the 

program. 

We are proposing, as part of the massbased federal plan and model rule, that 

a project is eligible to receive set-aside 

allowances if it is RE that meets the 

eligibility requirements for rate-based 

ERC issuance as specified in section 

IV.C of this preamble and section VIII.K 

of the final EGs. This includes, for 

example, the requirement that only 

capacity incremental to 2012 is eligible 

for the set-aside. The agency requests 

comment on an additional potential 

condition that would limit eligibility to 

project providers that are also the 

owners or operators of affected EGUs. 

This approach has precedent in the 

eligibility requirements for the ARP setaside, and would limit the entities 

eligible to receive set-aside allowances 

to those that are subject to the federal 

plan. 

The EPA is proposing that eligible RE 

capacity must meet the following 

conditions regarding geographic 

eligibility for both the federal plan and 

model rule. Eligible RE projects must be 

located in the mass-based state for 

which the set-aside has been designated. 

The agency invites comment on whether 

capacity outside the state should be 

recognized, and how that could be 

implemented. The EPA also proposes 

that the generation for which an entity 

receives allowances from the set-aside 

would not be eligible for ERC issuance 

in rate-based states. 

As specified in section IV.C of this 

preamble, the EPA is proposing that the 

same RE measures are eligible to receive 

set-aside allowances under a mass-based 

federal plan as would be eligible for 

ERC issuance under a rate-based federal 

plan and the model rule. Specifically, 

the following RE measures are eligible: 

On-shore wind, solar, geothermal 

power, and hydropower. The RE 

measure must also have the capacity to 

provide data quantified by a revenuequality meter, a requirement that is 

further discussed in section IV.D.8 of 

this preamble. New nuclear units and 

capacity uprates at existing nuclear 

units are not proposed to be eligible to 

receive set-aside allowances. We do not 

think a set-aside used as an incentive for 

incremental nuclear capacity is a useful 

way to address leakage to new sources 

during the performance period, due to 

unique costs and development timelines 

for incremental nuclear power. All other 

proposed aspects of the RE eligible 

measure types described in section IV.C 

of this preamble and the requests for 

comment included within that section 

also apply in the mass-based set-aside 

context for both the proposed massbased federal plan and the proposed 

mass-based model rule. For example, we 

are requesting comment on the 

inclusion of other RE measures, 

incremental nuclear, demand-side EE 

measures, CHP and any other emission 

reduction measures beyond those 

mentioned here, as long as they meet 

the eligibility requirements outlined in 

the final EGs for rate-based crediting, as 

eligible measures to receive set-aside 

allowances. We particularly request 

comment on how a set-aside to provide 

an incentive from these particular 

measures will serve to address leakage 

to new sources. We also request 

comment on the implications of the 

inclusion of such technologies for the 

streamlined implementation of 

projection-based EM&V requirements of 

the set-aside specified below in a federal 

plan context across the applicable 

jurisdictions, while still maintaining 

necessary rigor. We request comment on 

the appropriateness of the biomass 

treatment requirements offered for 

comment in section IV.C.3 of this 

preamble in the context of a mass-based 

set-aside. We request comment on 

requirements for the treatment of CHP 

and WHP, in the context of the massbased set-aside. We also request 

comment on appropriate processes 

through which, after the federal plan is 

finalized, the EPA and/or stakeholders 

could make a demonstration of the 

appropriateness of new measure types 

and the EPA could evaluate and 

approve the demonstration so that a 

new measure type can be considered 

eligible for the set-aside. 

To demonstrate that an RE project 

meets the requirements proposed above, 

in the context of a mass-based federal 

plan, it is proposed that the project 

proponent must provide the following: 

Documentation of the nature of the 

project and that it meets eligibility 

requirements, documentation that it will 

be located within the state in question, 

and a projection of expected annual 

MWh generation for an RE project. The 

EPA must approve the documentation of 

eligibility and the projection of MWh 

before the project becomes eligible for a 

distribution of the set-aside allowances. 

In addition, the proponent must register 

for a general account in the EPA 

tracking system where the allowances 

would be recorded. See 40 CFR 

62.16320 for the requirements to 

establish a general account. While the 

EPA is proposing to allow eligible 

resources to use a general account to 

receive any allowances allocated under 

this section, the EPA requests comment 

on extending the designated 

representative provisions in 40 CFR 

62.16290 to eligible resources instead of 

the general account provisions. 

Requiring eligible resources to submit 

information similar to that collected in 

the certificate of representation in 40 

CFR 62.16305 and to appoint a 

designated representative to act on 

behalf of all owners/operators for all 

projects requesting allowances may 

improve the EM&V process by making 

the eligible resources more accountable. 

The EPA requests comment on what 

documentation would be required if 

other measure types were considered 

eligible to receive set-aside allowances. 

We propose that the same process for 

approval of projects be applied in a 

model rule, with the state taking the 

approving role instead of EPA. 

The EM&V requirements for the massbased set-aside differ from those for 

rate-based ERC issuance, particularly 

because it is based upon projections 

provided prior to generation rather than 

metered data provided after the 

generation occurs (though we are 

proposing that the projections will be 

checked against ex-post metered data). 

The projection method enables the 

distribution of set-aside allowances 

prior to the year during which the 

generation occurs. The EPA feels this 

still provides sufficient rigor because 

the set-aside does not directly affect 

program stringency. The reason that 

stringency is not affected is because of 

key differences between issuance of 

credits and distribution of set-aside 

allowances. Under rate-based 

implementation, each decision to issue 

an ERC based on a quantification of RE 

generation affects the ultimate amount 

of allowable CO2 emissions, because the 

number of ERCs is determined by the 

amount of MWhs approved as eligible 

for ERC issuance and the ERC does not 

exist until the issuance decision is 

made. Thus the amount of ERCs that are 

issued can affect the stringency of the 

rule. As a result, the EPA has laid out 

specific requirements (including EM&V 

procedures) in the final Clean Power 

Plan, 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 setaside allowance allocations under a 

mass-based approach does not affect the 

validity of the allowance itself and does 

not affect the CO2 emissions outcome 

because the ultimate amount of 

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allowable CO2 emissions is determined 

by the total number of allowances 

initially created (regardless of how they 

are distributed). As a result, while the 

EPA believes it is reasonable to consider 

a minimum set of qualifications for 

recognizing RE through these allowance 

set-asides to assure that the RE 

generation that is incented is actually 

produced, the EPA does not believe the 

overall integrity of mass-based 

implementation is significantly affected 

by the robustness of whatever eligibility 

requirements the EPA ultimately sets for 

RE recognition through allocation from 

these set-asides. This being said, the 

agency is proposing to require robust 

demonstrations of the eligibility and 

EM&V projections for RE generation 

submitted for the set-aside, 

demonstrations that are based on the 

best practices of existing programs. This 

is necessary to assure the delivery of RE 

as a result of the set-aside. 

The EPA proposes that the projections 

of MWh provided will be the basis of 

the distribution of set-aside allowances. 

A satisfactory demonstration of the 

future RE generation from an eligible 

project must use technically sound 

quantification methods that are reliable, 

replicable, and accompanied by 

underlying analytical assumptions and 

verifiable data sources used to 

demonstrate future performance. These 

methods, assumptions and data sources 

must be specified in documentation 

accompanying the projections. These 

projections and supporting 

documentation should all be provided 

in the set-aside project application, and 

that application must be approved by a 

third-party verifier. The EPA invites 

comment on these proposed 

requirements for projections. We also 

request comment on whether set-asides 

should be distributed proportional to 

actual MWh provided by the installation 

in a prior year or compliance period, or 

another form of historical generation 

data. This type of allocation method 

could also be similar to the structure 

proposed for the output-based allocation 

set-aside. We propose that the same 

projection-based distribution basis be 

applied in a model rule, with the state 

taking the approving role instead of 

EPA. 

The EPA is proposing the following 

process for distribution of RE set-aside 

allowances. Starting prior to the 

compliance period, and going forward 

through the compliance period, RE 

providers in each state will have an 

opportunity to apply to the EPA or a 

designated agent to be approved as 

eligible to receive set-aside allowances 

in their state. This application must 

include all the requirements outlined 

above, including projections of expected 

MWh of generation. The EPA is 

proposing to accept RE set-aside project 

applications up to a deadline of June 1 

in the year prior to the year during 

which the RE generation occurs (the 

‘‘generation year’’). The EPA or its agent 

will review and approve the project as 

eligible and it will be entered into the 

pool of projects that will receive setasides in any compliance period. If 

approved, the number of projected 

MWh in each generation year will be the 

basis of the number of allowances the 

provider will receive, as an input to the 

methodology specified below. The 

providers will have an opportunity to 

update projections for future generation 

years, these projections must be 

received by June 1 of the year prior to 

the generation year in question. 

On December 1 of the year prior to 

each year of the compliance period in 

question, the EPA is proposing to 

distribute allowances from the set-aside 

to approved providers. The agency is 

proposing to distribute set-aside 

allowances to approved RE providers 

pro-rata, with the number of allowances 

distributed to each provider according 

to the percentage of total approved RE 

MWh for that state that the approved 

MWhs from their project represent. This 

method is proposed because it treats all 

eligible RE projects equally in the 

distribution of set-aside allowance. It 

also inherently provides a more 

significant incentive in states with less 

eligible RE generation, but will become 

less significant as RE generation 

increases. We also request comment on 

whether to restrict projects to a 

maximum number of allowances they 

can receive per MWh of generation, 

such as 1 allowance per MWh. 

After each generation year, RE 

providers receiving allowances will 

have to provide an M&V report with the 

MWhs 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 

section IV.D.8 of this preamble (EM&V 

section for the rate-based approach), 

these data should be readily available 

from existing metering. The EPA 

requests comment on the process for 

submitting M&V reports with actual 

generation. 

If the project or program does not 

reach the MWhs projected in a 

particular generation year, the 

unfulfilled MWhs will be subtracted 

from that RE provider’s MWhs eligible 

for the set-aside in the next generation 

year, or multiple years if the deficit 

exceeds the MWhs projected for the 

upcoming year. If this deficit is greater 

than 10 percent in a particular year, the 

provider will need to provide an 

explanation of the deficit and will be 

required to reevaluate their projections 

for future years. If such deficits continue 

through all years of the relevant 

compliance period, the provider will be 

disqualified from receiving future setasides for the following compliance 

period. We also request comment on 

whether a provider with continuing 

deficits should also be disqualified from 

receiving ERCs for the generation in 

question from states with rate-based 

plans. 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 setaside 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 set-aside allowances 

to eligible RE providers on December 1 

of the year prior to the generation year 

in question. The EPA requests comment 

on this approach. 

We propose that the same distribution 

process as outlined above be applied in 

a model rule, with the state taking the 

approving role instead of the EPA. 

The EPA is also seeking comment, in 

the context of the proposed rate-based 

federal plan and model rule, on whether 

a portion of this set-aside should be 

targeted to RE projects that benefit lowincome communities. This benefit could 

be in the form of MWh provided to the 

low-income community, financial 

proceeds from the project primarily 

benefiting the low-income community, 

or the project lowering utility costs of 

low-income rate-payers. The EPA seeks 

comment on how a low-income 

community should be defined as 

eligible under this set-aside. We seek 

comment on how much of the set-aside 

should be designated as targeted at 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, in the 

context of the proposed rate-based 

federal plan and model rule, on all 

aspects of this proposed RE allowance 

set-aside program, including whether it 

should be included as part of a massmstockstill on DSK4VPTVN1PROD with PROPOSALS2

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109As discussed in section VIII.B.2 of the final 

emission guidelines, in the case of a state that 

submits a final state plan including requirements 

for the state’s participation in the CEIP, eligible RE 

projects may commence construction, and eligible 

EE projects may commence implementation, 

following the date of submission of a final state 

plan to the EPA. These projects must be 

implemented in or benefit the state that submitted 

the final state plan to the EPA, and may receive 

awards for the zero-emitting MWh they generate or 

the end-use energy savings they achieve during 

2020 and/or 2021. 

110The 2012 baseline is from the CO2 Emission 

Performance Rate and Goal Computation TSD for 

the Clean Power Plan Final Rule. Where a state’s 

relative share of the reductions from 2012 levels 

would yield a set-aside of less than zero, the EPA 

proposes to assign such a state a set-aside equal to 

one percent of the state’s 2030 mass goal and adjust 

the remaining state set-asides accordingly. 

111This is the same distribution method proposed 

above for the allocation of early action set-aside 

allowances to mass-based federal plan states. 

112This may occur because not all states may 

elect to include requirements for CEIP participation 

in their state plans. 

based federal plan, the structure of the 

set-aside reserve, eligibility 

requirements for receiving set-aside 

allowances, demonstration of eligibility, 

and the process for distribution of 

allowances. 

4. Provisions To Encourage Early Action 

For purposes of the proposed massbased federal plan, the EPA proposes to 

implement the Clean Energy Incentive 

Program (CEIP) on behalf of a state by 

issuing early action allowances for 

eligible actions located in or benefitting 

the state. Eligible projects must 

commence construction in the case of 

RE or commence operations in the case 

of low-income EE after September 6, 

2018, and will receive incentives based 

on the zero-emitting MWh they 

generate, or the energy savings they 

achieve, during 2020 and/or 2021.109

These early action allowances would be 

drawn from a third set-aside of 

allowances from the general distribution 

methodology. The EPA believes it is 

reasonable to establish the total amount 

of the early action set-aside in an 

amount equal to the pool of matching 

allowances. Thus, the EPA proposes 

that the total early action set-aside 

would be of an amount equal to the pool 

of matching allowances: No more than 

300 million CO2 allowances, depending 

on how many states are subject to a 

federal plan. 

The EPA proposes to distribute the 

300 million early action set-aside 

allowances among the states based upon 

the amount of the reductions from 2012 

levels each state must achieve relative to 

that of the other participating states. The 

EPA proposes to calculate these values 

as each state’s proportional share of the 

total difference between the 2012 

baseline and the 2030 mass goals.110 See 

Table 10 of this preamble for the 

proposed set-asides for each state under 

the mass-based federal plan. The agency 

proposes to set aside 100 million early 

action allowances from each of the 3 

years in the first compliance period 

(2022, 2023, and 2024) for a total of 300 

million allowances to be set aside. 

While the table shows set-asides for 

every state, the EPA proposes to 

implement this set-aside, according to 

the amounts listed in Table 10, only for 

those states for whom the EPA is 

implementing the mass-based federal 

plan. The EPA also requests comment 

on other approaches for determining the 

size of this set-aside in the mass-based 

federal plan. 

For the purposes of the mass-based 

federal plan, the EPA is proposing to 

award early action allowances to two 

types of eligible projects that are located 

in or benefit the state for which the EPA 

is implementing a federal plan: 

• RE investments that generate 

metered MWh from any type of wind or 

solar resources; and 

• Demand-side EE programs and 

measures implemented in low-income 

communities that result in quantified 

and verified electricity savings (MWh). 

Eligible RE projects must commence 

construction, and eligible EE projects 

must commence implementation, after 

September 6, 2018 for those states on 

whose behalf the EPA is implementing 

the federal plan. These projects will 

receive incentives for the MWh they 

generate or the end-use energy demand 

reductions they achieve during 2020 

and/or 2021. 

The EPA proposes the following 

framework to implement the CEIP in the 

mass-based federal plan. First, the EPA 

proposes to create a set-aside of early 

action allowances for all federal plan 

states, as described above. Second, the 

agency proposes to create an account of 

‘‘matching’’ allowances for each state 

participating in the CEIP—regardless of 

whether a state is implementing a state 

plan or the agency is implementing a 

federal plan on its behalf. This 

distribution would reflect each state’s 

pro rata share of a federal pool of 

additional allowances—based on the 

amount of the reductions from 2012 

levels the affected EGUs in the state are 

required to achieve relative to those in 

the other participating states 111—which 

would be limited to the equivalent of 

300 million short tons of CO2 emissions. 

Thus, states whose EGUs have greater 

reduction obligations will be eligible to 

secure a larger proportion of the federal 

allocation upon demonstration of 

quantified and verified MWh of RE 

generation or demand side-EE savings 

from eligible projects realized in 2020 

and/or 2021. The EPA intends that a 

portion of these matching allowances 

would be reserved for eligible wind and 

solar projects, and a portion would be 

reserved for eligible EE projects 

implemented in low-income 

communities. The agency recognizes 

that there have been historical 

economic, logistical and information 

barriers to implementing EE programs in 

these communities, and therefore 

believes it is appropriate to reserve a 

portion of the federal pool to incentivize 

investment in these programs. The EPA 

requests comment on the size of reserve 

of matching allowances for eligible lowincome EE programs as well as for 

eligible wind and solar projects. The 

EPA is proposing that unused 

allowances in either reserve would be 

redistributed among participating states. 

This redistribution could be executed 

according to the pro-rata method 

discussed above. Alternatively, unused 

matching EE or RE allowances could be 

swept back into a federal pool and 

distributed to project providers on a 

first-come, first served basis. The EPA 

requests comment on these ideas as well 

as alternative proposals regarding the 

method for redistributing matching 

allowances, as well as the appropriate 

timing for such a redistribution. 

Following the effective date of a 

federal plan for a state, the agency will 

create an account of matching 

allowances for the state that reflects the 

pro rata share of the 300 million short 

ton CO2 emissions-equivalent matching 

pool that the state is eligible to receive. 

Any matching allowances that remain 

undistributed after September 6, 

2018 112 will be distributed to those 

states with approved state plans that 

include requirements for CEIP 

participation, as well as to those states 

on whose behalf the EPA is 

implementing a federal plan. These 

allowances will be distributed according 

to the pro rata method outlined above. 

Unused matching allowances that 

remain in the accounts of states 

participating in the CEIP on January 1, 

2023, will be retired by the EPA. The 

EPA seeks comment on whether the 

number of matching allowances 

available to a state under the mass-based 

federal plan should be limited to a 

number equal to the number of early 

action allowances included in each 

federal plan state’s early action setaside. 

Third, for any state subject to a federal 

plan, the EPA proposes to award early 

action allowances and matching 

allowances to eligible projects as 

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113This 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. 

follows, based upon the quantified and 

verified MWh of generation or savings 

achieved by the projects in 2020 and/or 

2021: 

• For RE projects that generate 

metered MWh from any type of wind or 

solar resources: For every two MWh 

generated, the project will receive a 

number of allowances equivalent to one 

MWh from the state early action 

allowance set-aside, and a number of 

matching allowances equivalent to one 

MWh from the EPA. 

• For EE projects implemented in 

low-income communities: For every two 

MWh in end-use demand savings 

achieved, the project will receive a 

number of allowances equivalent to two 

MWh from the state early action 

allowance set-aside, and a number of 

matching allowances equivalent to two 

MWh from the EPA. 

The EPA will address implementation 

details of the CEIP in a subsequent 

action. Allowances awarded by the EPA 

pursuant to the CEIP may be used for 

compliance by an affected EGU with its 

emission standards in any compliance 

period and are fully transferrable prior 

to such use. The EPA proposes to 

distribute any remaining early action 

set-aside allowances in a state—after 

distribution to all eligible projects in the 

state—to the affected EGUs in the state 

on a pro-rata basis in proportion to the 

initial allocations made to those EGUs 

under the mass-based federal plan. 

As discussed in section V.E of this 

preamble, the EPA proposes to allow 

any state where a federal plan is being 

implemented to take responsibility for 

distributing allowances. This will allow 

a state to tailor its allowancedistribution approach to the 

characteristics and preferences of the 

state. The EPA proposes that a state that 

chooses to replace the federal plan 

allocations with a state-determined 

approach must include a CEIP set-aside, 

as authorized in section VIII.B.2 of the 

final EGs. The EPA intends that such a 

state would have the same flexibilities 

as a state implementing a full state plan 

with respect to implementation of the 

CEIP. That is, the state would not be 

required to implement a set-aside of the 

same size as proposed in Table 10 of 

this preamble, but rather could choose 

how many of its allowances to set-aside 

for the CEIP. 

The EPA requests comment on all 

aspects of implementing the CEIP under 

a mass-based federal plan approach, 

including (1) The size of the early action 

allowance set-aside; (2) the approach for 

distributing the early action allowance 

set-aside among states; (3) the timing of 

distribution of set-aside and matching 

allowances; (4) the amount of 

allowances awarded per eligible MWh 

generated or avoided; (5) the criteria for 

eligible projects, including criteria for 

awards to EE projects implemented in 

low-income communities; (6) the 

mechanism for reviewing project 

submittals and issuing early action 

allowances; (7) EM&V requirements for 

eligible projects; and, (8) the number of 

early action and matching allowances 

that should be awarded for each ton of 

emissions reduced from eligible 

generation or low-income efficiency 

projects to ensure a robust response to 

the program. The EPA also seeks 

comment on how states, tribes and 

territories for whom goals have not yet 

been established in the final EGs may be 

able to participate in the CEIP in the 

future. 

The EPA also requests comment on 

the proposed approach of requiring 

states to implement this program as a 

condition of a state choosing to 

determine its own allocation approach 

via a partial state plan or a delegation 

of the federal plan. 

TABLE 10—PROPOSED CLEAN ENERGY

INCENTIVE PROGRAM EARLY ACTION

ALLOWANCE SET-ASIDE IN THE

MASS-BASED FEDERAL PLAN

[Short tons] 

State 

Set-aside 

2022 through 

2024 

Alabama ................................ 3,122,306 

Arizona .................................. 1,719,618 

Arkansas ............................... 2,187,230 

California ............................... 218,846 

Colorado ............................... 2,223,192 

Connecticut ........................... 69,415 

Delaware ............................... 138,392 

Florida ................................... 3,230,248 

Georgia ................................. 2,755,623 

Idaho ..................................... 14,929 

Illinois .................................... 5,968,721 

Indiana .................................. 5,754,076 

Iowa ...................................... 2,191,183 

Kansas .................................. 2,115,630 

Kentucky ............................... 4,952,862 

Lands of the Fort Mojave 

Tribe .................................. 5,885 

Lands of the Navajo Nation .. 1,623,066 

Lands of the Uintah and 

Ouray Reservation ............ 175,509 

Louisiana .............................. 1,497,428 

Maine .................................... 20,739 

Maryland ............................... 972,775 

Massachusetts ...................... 170,471 

Michigan ............................... 3,727,861 

Minnesota ............................. 2,002,903 

Mississippi ............................ 357,307 

Missouri ................................ 3,771,322 

Montana ................................ 1,310,344 

Nebraska .............................. 1,481,695 

Nevada ................................. 336,288 

New Hampshire .................... 107,798 

New Jersey ........................... 446,005 

New Mexico .......................... 823,049 

TABLE 10—PROPOSED CLEAN ENERGY

INCENTIVE PROGRAM EARLY ACTION

ALLOWANCE SET-ASIDE IN THE

MASS-BASED FEDERAL PLAN—Continued 

[Short tons] 

State 

Set-aside 

2022 through 

2024 

New York .............................. 557,771 

North Carolina ...................... 2,674,590 

North Dakota ........................ 2,150,635 

Ohio ...................................... 4,788,372 

Oklahoma ............................. 2,067,006 

Oregon .................................. 154,353 

Pennsylvania ........................ 5,039,346 

Rhode Island ........................ 35,674 

South Carolina ...................... 1,652,802 

South Dakota ........................ 264,207 

Tennessee ............................ 2,178,084 

Texas .................................... 10,400,192 

Utah ...................................... 1,401,189 

Virginia .................................. 1,386,546 

Washington ........................... 751,434 

West Virginia ........................ 3,506,890 

Wisconsin ............................. 2,393,870 

Wyoming ............................... 3,104,324 

5. Allocations to Units That Change 

Status 

Units that retire. The EPA proposes 

that, if an affected EGU does not operate 

for 2 consecutive calendar years, the 

unit would continue to receive 

allocations for a limited number of years 

after it ceases operation, after which the 

allowances that would otherwise have 

been allocated to that unit would be 

allocated to the RE set-aside for the state 

in which the retired unit is located.113

Continuing allocations to non-operating 

units for a period of time reduces the 

incentive to keep a unit operating 

simply to avoid losing the allowance 

allocations for that unit (e.g., a unit that 

would otherwise be retired due to age 

and inefficiency). On the other hand, 

non-operating units are no longer 

emitting and so do not need allowances. 

The EPA believes that the proposed 

approach of allocating allowances for a 

specified, but limited, period after a unit 

ceases operating is a reasonable middle 

ground approach. The proposed 

approach also allows the RE set-asides 

to grow over time. 

The EPA proposes to record 

allowances for each year of a multi-year 

compliance period at once, 7 months 

prior to the start of each compliance 

period, as discussed above. The agency 

proposes that, if an affected EGU does 

not operate for 2 full calendar years, 

then starting with the next compliance 

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period for which allowances have not 

yet been recorded, the allowances that 

would otherwise have been allocated to 

the unit would be allocated to the RE 

set-aside. As a result, the number of 

years of non-operation for which a 

retired unit would receive allocations 

would vary depending on when a unit 

retires. For example, if an affected EGU 

does not operate for the first two 

calendar years of a 3-year compliance 

period, then starting with the next 

compliance period the allowances that 

would otherwise have been allocated to 

that unit would be allocated to the RE 

set-aside—in other words the unit 

would receive allocations for 3 years of 

non-operation. As a further example, if 

an affected EGU does not operate for 

both calendar years of a 2-year 

compliance period, then starting with 

the compliance period after the next 

compliance period the allowances 

would be allocated to the RE set-aside— 

in other words the unit would receive 

allocations for 4 years of non-operation. 

The agency requests comment on this 

approach for treatment of allocations to 

affected EGUs that retire, including on 

the number of years of non-operation for 

which a unit would continue to receive 

allocations. The EPA also requests 

comment on an alternative of 

distributing such allowances to the setaside for output-based allocations, or to 

the remaining affected EGUs in the state 

in a pro-rata fashion (on the same 

distribution basis as the initial 

allocations were made), instead of 

allocating such allowances to the state’s 

RE set-aside. The agency requests 

comment on a further alternative 

approach, which would be to continue 

allocations to the retired units. The EPA 

also requests comment on treatment of 

allocations to units that are in long-term 

cold storage. 

Units that are modified or 

reconstructed. Similar to the approach 

for an affected EGU that retires, the EPA 

proposes that, if a unit is modified or 

reconstructed such that it is no longer 

an affected EGU, then starting with the 

next compliance period for which 

allowances have not yet been recorded, 

the allowances that would otherwise 

have been allocated to the unit would be 

allocated to the RE set-aside. The EPA 

requests comment on this proposed 

approach, including on the number of 

years for which a unit would continue 

to receive allocations. The agency also 

requests comment on an alternative of 

distributing such allowances to the setaside for output-based allocations, or to 

the remaining affected EGUs in the state 

in a pro-rata fashion (on the same 

distribution basis as the initial 

allocations were made), instead of 

allocating such allowances to the state’s 

RE set-aside. The agency requests 

comment on a further alternative 

approach, which would be to continue 

allocations to the modified or 

reconstructed units. 

E. State-Determined Allowance 

Distribution 

The EPA proposes to allow any state 

to replace the EPA-determined federal 

plan allowance-distribution provisions 

in the mass-based trading program with 

state-developed allowance-distribution 

provisions. In this way, a state could 

choose how to distribute initial 

allowance allocations among its affected 

EGUs (and other entities). 

The EPA believes that this option may 

offer significant appeal, because it will 

allow a state to tailor its allocation 

approach to the characteristics and 

preferences of the state. A state would 

be able to design its allocation approach 

to address its particular state priorities, 

whether they are protecting low-income 

consumers, supporting local industries, 

or other goals. The EPA anticipates that 

a state would have great flexibility in its 

allowance distribution approach and 

could take advantage of allocation 

options discussed in this proposal as 

well as other allocation options a state 

might prefer. States could auction 

allowances and rebate the revenue to 

consumers, or allocate all allowances to 

load-serving entities, while mandating 

that the value be passed through to 

vulnerable consumers. The EPA 

believes that the state-determined 

allocation approach offers significant 

advantages and solicits comment on 

how to ease its application by states. 

This is similar to the approach taken in 

CSAPR and CAIR where the EPA 

adopted rules allowing states to submit 

SIPs with provisions replacing the 

allowance-distribution provisions in the 

CSAPR or CAIR FIPs, respectively, 

while remaining in the trading programs 

under those FIPs (76 FR 48208; August 

8, 2011, 71 FR 25328; April 28, 2006). 

In both CSAPR and CAIR, some states 

have chosen to determine their own 

allocations under the FIPs. This form of 

SIP that can replace the allowancedistribution provisions in CSAPR or 

CAIR is termed an ‘‘abbreviated SIP 

revision.’’ In this proposed mass-based 

trading federal plan, the EPA proposes 

that a state may choose to submit a 

‘‘state allowance-distribution 

methodology’’ (analogous to an 

abbreviated SIP revision) to replace the 

federal plan 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 allowancedistribution methodology. The EPA 

proposes that a state may choose any 

approach, including auctions or other 

methods the EPA is not proposing here, 

provided the state’s approach addresses 

leakage and also implements the Clean 

Energy Incentive Program. The EPA is 

also requesting comment on any other 

appropriate constraints to impose on 

state allowance-distribution 

methodologies. 

The Clean Power Plan EGs require 

mass-based state plans to include a 

demonstration that they have addressed 

the risk of leakage, and the EGs provide 

several options for doing so (see 

sections VII.D and VIII.J of the final 

EGs). One of the options provided in the 

EGs is to address leakage through an 

allowance distribution approach that 

provides incentive to counteract 

leakage. In the mass-based trading 

federal plan, the EPA’s proposed 

approach to allocate allowances would 

address leakage using two allowance 

set-asides, one for output based 

allocation and one for RE projects, as 

detailed in section V.D.3 of this 

preamble. The EPA believes that a state 

allowance-distribution methodology, 

which would replace the federal plan 

allocation provisions, must also address 

leakage. The EPA proposes that a state 

allowance-distribution methodology 

must address leakage by providing 

incentive to counteract leakage, e.g., by 

including allowance set-asides like the 

output-based allocation and RE setasides detailed in section V.D.3 of this 

preamble, or other allocation 

approaches designed to counteract 

leakage. The EPA requests comment on 

this proposed approach for addressing 

leakage in a state allowance-distribution 

methodology and on any other 

approaches for doing so. The EGs 

provide an additional option for state 

plans to address leakage, where a state 

would provide a demonstration that 

leakage will not occur (without 

implementing any of the strategies 

specified in the EGs) due to specified 

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114A 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. 

characteristics of the state (section VIII.J 

of the final EGs). In this federal plan 

proposal, the EPA requests comment on 

an alternative option where a state that 

chooses to submit a state allowancedistribution methodology could provide 

a demonstration that leakage will not 

occur (without implementing the 

allocation strategies specified here) due 

to specific characteristics of the state; 

the EPA proposes that such 

demonstration must meet the 

requirements in the final EGs, including 

support by credible analysis, for such a 

demonstration (see final EGs section 

VII.D). The EPA notes that a state’s 

allowance-distribution methodology 

may also include other set-aside 

approaches that are not designed to 

counteract leakage. 

The Clean Power Plan EGs established 

a Clean Energy Incentive Program 

(section VIII of the final EGs). The EPA 

proposes that a state allowancedistribution methodology, which would 

replace the federal plan allocation 

provisions, must also include a Clean 

Energy Incentive Program, as detailed in 

section V.D.4 of this preamble. 

Under the proposed approach of 

providing for states to determine their 

allowance distribution approaches in 

the federal plan mass-based trading 

program, the affected EGUs in a state 

that submitted a state allowancedistribution methodology, which the 

EPA approved, would participate in the 

federal plan mass-based trading 

program, but with allowance 

distribution determined by the state 

instead of by the EPA. 

The EPA proposes that a state must 

submit to the Administrator tables 

specifying the unit-level allowances in 

an electronic format specified by the 

Administrator and by the specified 

deadlines applicable to each compliance 

period (see Table 11 of this preamble for 

proposed submission deadlines). 

The EPA proposes that a state may 

submit a state allocation methodology 

for any compliance period, including 

the first compliance period, which 

would comprise the years 2022, 2023, 

and 2024. The EPA proposes that a state 

submitting a state allowancedistribution methodology to modify the 

federal plan allowance-distribution 

provisions must do so for all years 

within a compliance period (e.g., for all 

3 years in a 3-year compliance period). 

The EPA proposes that, if the state’s 

allowance-distribution 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 allowancedistribution methodology, the state 

could distribute allowances to affected 

EGUs or other entities (such as RE 

facilities) or could auction some or all 

of the allowances. The agency proposes 

that for EPA approval, the state 

allowance-distribution methodology 

provisions would have to meet the 

following requirements. The provisions 

would have to address leakage as 

discussed above. The provisions would 

have to provide that, for each year for 

which the state allowance-distribution 

provisions would apply, the total 

amount of allowances distributed could 

not exceed the applicable mass goal for 

that state for that year. A state’s 

methodology under this proposed 

approach could provide that the total 

amount of allowances distributed is less 

than the applicable mass goal.114 The 

EPA proposes that a state’s allowancedistribution provisions would replace 

the EPA’s allocation provisions 

completely—a state would not have the 

option of implementing only a portion 

of its allocations (e.g., only set-asides) 

and having the EPA implement the 

remainder of its allocations. 

Additionally, the EPA proposes that a 

state allowance-distribution 

methodology must provide for 

allowances to be issued in short tons. 

The allocation (or auction) of 

allowances would be final and could 

not be subject to modification. 

Additionally, the state’s provisions 

could not change any other provisions 

of the proposed mass-based trading 

program with regard to the allowances 

(e.g., the deadlines for allocation 

recordation, or requirements for transfer 

or use of allowances) or any other aspect 

of such trading programs. 

In order for a state allowancedistribution methodology’s provisions 

to replace the EPA’s allowancedistribution provisions for a given 

compliance period, a state would have 

to submit the state allowancedistribution methodology by a deadline 

that would provide the agency sufficient 

time to review and approve it, and to 

submit the allowance table meeting the 

specified electronic format by a 

deadline that would provide sufficient 

time to record the unit-by-unit 

allowances in source accounts. The EPA 

believes that about 12 months—starting 

from the date of receipt of a state 

allowance-distribution methodology—is 

sufficient to complete the agency’s 

review and approval process, which 

would have to provide an opportunity 

for public comment on the approval (or 

disapproval) action. Thus, the EPA 

proposes the following deadlines, in 

Table 11 of this preamble, for 

submission to the agency of state 

allowance-distribution methodologies 

and unit-level allowances, and for the 

EPA’s recordation of allowances, for 

each compliance period. The EPA 

would review and approve state 

allowance-distribution methodologies in 

the 12 months between the proposed 

deadline for states to submit their 

methodologies and the proposed 

deadline for states to submit unit-level 

allowance tables. The proposed 

deadline for submission of allowance 

tables is 3 months before the proposed 

deadline for the agency to record 

allowances in source accounts. The EPA 

proposes to record allowances in source 

accounts by the recordation deadlines. 

TABLE 11—PROPOSED DEADLINES FOR SUBMISSION OF STATE ALLOWANCE-DISTRIBUTION METHODOLOGIES AND UNITLEVEL ALLOWANCES AND FOR RECORDATION

First compliance period for which allowances would be 

distributed 

Deadline for submittal of state 

allowance-distribution 

methodologies 

Deadline for submittal of 

unit-level allowance table 

Deadline for the 

EPA to record 

allowances 

2022, 2023, 2024 ..................................................................... March 1, 2020 ........................ March 1, 2021 ........................ June 1, 2021. 

2025, 2026, 2027 ..................................................................... March 1, 2023 ........................ March 1, 2024 ........................ June 1, 2024. 

2028, 2029 ............................................................................... March 1, 2026 ........................ March 1, 2027 ........................ June 1, 2027. 

2030, 2031 * ............................................................................. March 1, 2028 * ...................... March 1, 2029.* ..................... June 1, 2029 * 

* This pattern of deadlines would hold for successive 2-year compliance periods. 

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The proposed deadlines for 

submission of state allowancedistribution methodologies are later 

than the state plan submission 

deadlines promulgated in the Clean 

Power Plan EGs. The agency anticipates 

that it can complete the approval 

process relatively quickly for a state 

allowance-distribution methodology 

due to its narrow scope. 

The agency proposes to record the 

EPA-determined federal plan allocations 

only in the absence of an approved state 

plan or approved state allowancedistribution methodology. The EPA 

proposes to record in source accounts 

allowances that are determined by any 

state as soon as feasible after approval 

of a state allowance-distribution 

methodology and submission of the 

unit-level allowance table, and not to 

wait until the allowance recordation 

deadline to do so. 

In section V.D.2 of this preamble, the 

EPA proposes that the allowance 

recordation deadline be 7 months prior 

to the start of the compliance period 

(i.e., June 1 of the prior year) and also 

requests comment on a recordation 

deadline 13 months prior to the start of 

the compliance period (i.e., December 1 

of the year, 2 years before the 

compliance period starts). If the EPA 

adopted the earlier recordation deadline 

on which it requests comment or any 

other deadline, then we would adjust 

the deadlines for submission of state 

allowance-distribution methodologies 

and submission of unit-level allowance 

tables accordingly. 

The EPA proposes that a state may not 

replace EPA-determined allocations for 

a compliance period for which federal 

plan allocations have already been 

recorded, for the same reasons that the 

agency proposes that a state may not 

replace a mass-based trading federal 

plan with a state plan for a future 

compliance period for which 

allowances have already been recorded, 

as discussed below in section V.F of this 

preamble. 

The agency requests comment on the 

proposed approach to allow states to 

determine allocations via state 

allowance-distribution methodologies 

and replace the federal plan allowancedistribution provisions. The EPA 

requests comment on the proposed 

schedule for submitting state allowance 

distribution methodologies to the 

agency, for submitting the resulting 

unit-level allowance tables to the 

agency, and for the agency to record 

allowances. The EPA requests comment 

on its proposed approach of not 

replacing EPA-determined allocations 

for a compliance period for which 

allowances have already been recorded. 

The agency also requests comment on 

an alternative approach where a state 

could notify the EPA of its intent to 

submit a state allowance-distribution 

methodology in advance, in which case 

the agency would hold off on recording 

EPA-determined allocations to allow 

more time for state-determined 

allowances to be recorded, similar to the 

alternative timing approach discussed 

in section V.F of this preamble. 

The EPA is also requesting comment 

on an alternative approach to provide 

the opportunity for a state to determine 

its allowance-distribution provisions in 

the federal plan mass-based 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 allowancedistribution provisions—to a state that 

wishes to determine its allowancedistribution provisions. The EPA 

requests comment on the relative 

efficiency and ease of implementation of 

the two approaches (the state allowancedistribution methodology described 

above, or the partial delegation). The 

agency requests comment on whether 

the partial delegation approach would 

provide sufficient flexibility for a state 

to choose any method to distribute its 

allowances including approaches that 

the EPA is not proposing here. See 

further discussion of delegations in 

section VI of this preamble. 

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 mass-based trading federal plan 

could only be replaced by a state plan 

for a future compliance period for 

which allowances have not yet been 

recorded. For example, if a 3-year 

compliance period comprises 2022, 

2023, and 2024, the EPA would record 

allowances in source accounts for 2022, 

2023, and 2024 prior to 2022. Once 

2022, 2023, and 2024 allowances had 

been recorded, the first compliance 

period for which a state could replace 

the federal plan with its own plan 

would be for the period commencing in 

2025. The EPA is proposing this 

stipulation for the timing of replacing a 

federal plan with a state plan due to the 

need to avoid disruption to sources 

already subject to the mass-based 

trading federal plan. Without this 

stipulation, a state might withdraw from 

the mass-based trading program in the 

middle of a compliance period even 

though allowances that authorize 

emissions throughout that entire 

compliance period would already be in 

circulation. In that circumstance, the 

EPA would then need to address 

whether and how to remove those 

allowances from circulation to prevent 

inflation of the allowable emissions at 

affected EGUs in the remaining states 

subject to the federal plans beyond the 

levels specified in the Clean Power Plan 

EGs. The EPA believes it is more 

reasonable to avoid this potential 

disruption by requiring that the 

replacement of a federal plan with a 

state plan be scheduled to coincide with 

the conclusion of the last compliance 

period for which allowances under the 

federal plan have already been recorded 

for that state. The EPA requests 

comment on other approaches to 

provide a smooth transition from federal 

plan implementation to implementation 

by state plans, and on its proposed 

approach of not replacing a federal plan 

for any compliance period for which 

allowances were already recorded. 

The agency requests comment on an 

alternative of providing for a state to 

give notice to the EPA of its intent to 

submit a state plan to replace the federal 

plan (or a state allowance-distribution 

methodology to replace federal plan 

allocations), and for the agency to delay 

recording federal plan allocations for 

sources in that state until a later date 

than proposed. The EPA requests 

comment on whether this alternative 

would help smooth the transition from 

federal plan implementation to state 

plan implementation, and on the tradeoff 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 massbased trading program use an ATCS 

operated essentially the same way as the 

existing systems that are currently in 

use for CSAPR and the ARP under Title 

IV. Under the proposed mass-based 

trading program, the CO2 program 

would be a separate trading program 

maintained in the EPA’s existing data 

system. ATCS would be used to track 

the trading of CO2 allowances held by 

covered affected EGUs in facility level 

compliance accounts, as well as such 

allowances held by other entities or 

individuals. Specifically, ATCS would 

track the allocation of all CO2

allowances, holdings of CO2 allowances 

in compliance accounts (i.e., a facility 

level account for all affected EGUs at the 

facility) and general accounts (i.e., 

accounts for other entities such as 

companies and brokers), deduction of 

CO2 allowances for compliance 

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purposes, and transfers of allowances 

between accounts. The primary role of 

ATCS is to provide an efficient, 

automated means for affected EGUs to 

comply, and for the EPA to determine 

whether affected EGUs are complying, 

with the emissions limitations and any 

other requirements of the mass-based 

trading program. ATCS would also 

provide data to the allowance market 

and the public, including a record of 

ownership of allowances, dates of 

allowance allocations, allowance 

transfers, buyer and seller information, 

serial numbers of allowances 

transferred, emissions, and compliance 

information. This information would be 

publicly available on the EPA’s Web site 

and in annual progress reports. 

1. Designated Representatives and 

Alternate Designated Representatives 

The EPA proposes to establish 

procedures for certifying and 

authorizing the designated 

representative, and alternate designated 

representative, of the owners and 

operators of an affected EGU and for 

changing the designated representative 

and alternate designated representative. 

The proposed provisions 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 are patterned after the 

provisions concerning designated 

representatives and alternates in prior 

EPA-administered trading programs. 

Under the proposed provisions, the 

designated representative would be the 

individual authorized to represent the 

owners and operators of each affected 

EGU in matters pertaining to the massbased trading program. One alternate 

designated representative could also be 

selected to act on behalf of, and legally 

bind, the designated representative and 

thus the owners and operators. Because 

the actions of the designated 

representative and alternate would 

legally bind the owners and operators, 

the designated representative and 

alternate would have to submit a 

certificate of representation certifying 

that each was selected by an agreement 

binding on all such owners and 

operators and was authorized to act on 

their behalf. 

The designated representative and 

alternate would be authorized upon 

receipt by the Administrator of the 

certificate of representation. This 

document, in a format prescribed by the 

Administrator, would include: Specified 

identifying information for the affected 

EGU and for the designated 

representative and alternate; the name 

of every owner and operator of the 

affected EGU; and certification language 

and signatures of the designated 

representative and alternate. All 

submissions (e.g., monitoring plans, 

monitoring system certifications, and 

allowance transfers) for an affected EGU 

would have to be submitted, signed, and 

certified by the designated 

representative or alternate. Further, 

upon receipt of a complete certificate of 

representation, the Administrator would 

establish a compliance account in the 

ATCS for each facility with an affected 

EGU involved. 

In order to change the designated 

representative or alternate, a new 

certificate of representation would have 

to be received by the Administrator. A 

new certificate of representation would 

also have to be submitted to reflect 

changes in the owners and operators of 

the affected EGU involved. However, 

new owners and operators would be 

bound by the existing certificate of 

representation even in the absence of 

such a submission. 

In addition to the flexibility provided 

by allowing an alternate to act for the 

designated representative (e.g., in 

circumstances where the designated 

representative might be unavailable), 

additional flexibility would be provided 

by allowing the designated 

representative and alternate to delegate 

authority to make electronic 

submissions on his or her behalf. The 

designated representative and alternate 

could designate agents to submit 

electronically certain specified 

documents. The previously-described 

requirements for designated 

representatives and alternates would 

provide regulated entities with 

flexibility in assigning responsibilities 

under the mass-based trading program, 

while ensuring accountability by 

owners and operators and simplifying 

the administration of the proposed 

mass-based trading program. 

2. Allowance Tracking and Compliance 

System 

The proposed mass-based trading 

program rules include procedures and 

requirements for using and operating 

the ATCS (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. Under the 

proposed rules, 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 

EPA-administered trading programs, 

allowance price information would not 

be included in the ATCS. The EPA’s 

experience is that private parties (e.g., 

brokers) are in a better position to obtain 

and disseminate timely, accurate 

allowance price information than is the 

EPA. For example, because not all 

allowance transfers are immediately 

reported to the Administrator for 

recordation, the Administrator would 

not be able to ensure that any reported 

price information associated with the 

transfers would reflect current market 

prices. 

3. Compliance and General Accounts 

The proposed provisions addressing 

compliance and general accounts 

describe two types of ATCS 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 EGUlevel accounts, would provide owners 

and operators more flexibility in 

managing their allowances for 

compliance, without jeopardizing the 

environmental goals of the mass-based 

trading program, because the facilitylevel 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 EPAadministered mass-based trading 

programs. 

General accounts could be used by 

any person or group for holding or 

trading allowances. However, 

allowances could not be used for 

compliance with emissions limitations 

so long as the allowances were held in, 

and not properly and timely transferred 

out of, a general account. To open a 

general account, a person or group 

would have to submit an application for 

a general account, which would be 

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similar in many ways to a certificate of 

representation. The application would 

include, in a format prescribed by the 

Administrator: The name and 

identifying information of the 

individual who would be the authorized 

account representative and of any 

individual who would be the alternate 

authorized account representative; an 

identifying name for the account; the 

names of all persons with an ownership 

interest with respect to allowances held 

in the account; and certification 

language and signatures of the 

authorized account representative and 

alternate. The authorized account 

representative and alternate would be 

authorized upon receipt of the 

application by the Administrator. The 

provisions for changing the authorized 

account representative and alternate, for 

changing the application to take account 

of changes in the persons having an 

ownership interest with respect to 

allowances, and for delegating authority 

to make electronic submissions would 

be analogous to those applicable to 

comparable matters for designated 

representatives and alternates. 

4. Recordation of Allowance Allocations 

and Transfers 

The EPA proposes to establish the 

following schedule and procedures for 

recordation of allowance allocations and 

transfers. By June 1, 2021, the 

Administrator would record allowance 

allocations for EGUs for 2022 through 

2024. Then, by June 1 of the year prior 

to the beginning of each compliance 

period, the Administrator would record 

the allowance allocations for the 

proposed mass-based trading program 

for each year within that next 

compliance period, e.g., for 2025, 2026, 

and 2027 by June 1, 2024. Recording 

these allowance allocations in advance 

of the first year for which they could be 

used for compliance would facilitate 

compliance planning by owners and 

operators and promote robust allowance 

markets, including futures markets for 

allowances. 

Under the proposed provisions, the 

process for transferring allowances from 

one account to another would be quite 

simple. Allowances could be transferred 

by submitting a transfer form 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 a 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 

The EPA proposes to include the 

following provisions regarding 

compliance with emission limitations. 

Under the proposed provisions, once 

the compliance period has ended (e.g., 

at midnight on December 31, 2024 for 

the first compliance period), facilities 

with affected EGUs would have a 

window of opportunity following the 

compliance period to evaluate their 

reported emissions and obtain any 

allowances that they might need to 

cover their emissions during the 

compliance period. For example, the 

allowance transfer deadline for the first 

compliance period would be midnight 

on May 1, 2025 (the EPA is also 

requesting comment on earlier or later 

allowance transfer deadlines). Each 

allowance issued in the proposed massbased trading program would authorize 

emission of one ton of CO2 and so 

would be usable for compliance, for the 

compliance period that includes the 

year for which the allowance was 

allocated or a later compliance period. 

Consequently, each affected EGU would 

need, as of the allowance transfer 

deadline, to have in its facility 

compliance account, or to have a 

properly submitted transfer that would 

move into its compliance account, 

enough allowances usable for 

compliance to authorize its total 

emissions for the compliance period. 

The authorized account representative 

could identify specific allowances to be 

deducted, but, in the absence of such 

identification or in the case of a partial 

identification, the Administrator would 

deduct on a first-in, first-out basis. 

Deducting allowances may have tax and 

accounting implications, so having a 

default deduction method provides the 

representatives with certainty regarding 

which allowances will be deducted for 

compliance. Allowances that are 

deducted for compliance will remain in 

the system in an EPA account, which 

ensures they will not be used again. If 

a facility were to fail to hold sufficient 

allowances for compliance by all 

affected EGUs at the facility, then the 

owners and operators of the facility and 

each affected EGU at the facility would 

have to provide, for deduction by the 

Administrator, two allowances allocated 

for the compliance period in the next 

year for every allowance that the owners 

and operators failed to hold as required 

to cover emissions. This submittal of 

two times the allowances required for 

the prior period is an ongoing obligation 

until compliance is achieved, and there 

is an ongoing obligation to comply in 

the current period. In addition, these 

owners and operators would be subject 

to civil penalties for each violation in 

accordance with the CAA, with each ton 

of unauthorized emissions and each day 

of the compliance period involved 

constituting a violation of the CAA. 

The EPA believes that it is important 

to include a requirement for an 

automatic deduction of allowances. The 

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 noncompliance would be a significantly 

more expensive option than 

compliance. Such automatic deductions 

have been successfully used in prior 

programs including the CAIR, achieving 

compliance rates close to 100 percent. 

6. Other Allowance Tracking and 

Compliance Operations Provisions 

The proposed provisions regarding 

allowance tracking and compliance also 

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 

ATCS. In addition, the Administrator 

could review any submission under the 

mass-based trading program, make 

adjustments to the information in the 

submission, and deduct or transfer 

allowances based on such adjusted 

information. These provisions are a 

standard part of other trading programs 

administered by the EPA including the 

ARP and Cross State Air Pollution Rule 

(see 40 CFR 72.96, 73.37, 97.427, and 

97.428). 

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 

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65032 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Proposed Rules 

115As discussed in section VI.D of this preamble, 

tribes with affected EGUs 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. 

116As discussed in section VI.D of this preamble, 

in adopting a federal plan implementing the EGs in 

areas of Indian country containing affected EGUs, 

the EPA must determine that such a plan is 

‘‘necessary or appropriate’’ to protect air quality. 

See 40 CFR 49.11(a). 

117 If the Administrator chooses to retain certain 

authorities under a standard, those authorities 

cannot be delegated, e.g., the authority to allow 

alternative methods of demonstrating compliance. 

118We 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; 

November 25, 2002); Final Federal Plan for CISWI 

(68 FR 57518, 57535; October 3, 2003). 

119A tribe interested in taking delegation of the 

federal plan must also apply, and be approved by 

the EPA, for TAS eligibility for that purpose. See 

40 CFR part 49. 

required, with each quarterly report due 

to the Administrator 30 days after the 

last day in the quarter. The reporting 

would be in accordance with 40 CFR 

75.60. The use of 40 CFR part 75 

certified monitoring methodologies 

would be required. Many EGUs that 

might be covered by the proposed 

federal plans will generally have no 

changes to their monitoring and 

reporting requirements and will 

continue to monitor and submit reports 

under 40 CFR part 75 as they have 

under existing programs. The EPA 

anticipates fewer than 50 affected EGUs 

that would not otherwise be subject to 

the ARP will have to purchase and 

install additional CEMS and data 

handling systems or upgrade existing 

equipment in order to meet the 

monitoring and reporting requirements 

of this program (the EPA anticipates 

approximately 10 coal fired units and 

approximately 40 gas and oil fired units 

will qualify for an excepted monitoring 

methodology). Several of the units not 

otherwise subject to the ARP are subject 

to the MATS program and, therefore, 

will have already installed stack flow 

rate and/or CO2 monitors necessary to 

comply with this rule in order to 

comply with the MATS. The CEMS 

used to comply and report data for 

MATS will be used for this rule to 

generate and report CO2 emissions data 

without having to install duplicative 

monitors. The same CO2 and stack gas 

flow rate monitored data used in 

conjunction with mercury and other 

CEMS to calculate a toxic pollutant 

emission rate may be used to calculate 

a CO2 mass or CO2 emission rate for this 

program. RGGI, ARP, MATS and this 

rule all refer to CEMS installed and 

certified in accordance with 40 CFR part 

75. RGGI and ARP currently require the 

reporting of CO2 mass emissions on an 

hourly basis and cumulative totals at the 

end of each calendar quarter. The same 

monitors and data collected may be 

used for multiple purposes for RGGI, 

ARP, MATS and this rule. Relying on 

the same monitors that are certified and 

quality ensured in accordance with 40 

CFR part 75 ensures cost efficient, 

consistent, and accurate data that may 

be used for different purposes for 

multiple regulatory programs. 

The majority of the units covered by 

this rule are already affected by the Acid 

Rain and/or RGGI programs and will 

have minimal additional monitoring 

and reporting requirements. 

The EPA also requests comment on 

requiring monitoring and reporting of 

CO2 mass and net generation for the 

year before the initial compliance 

period begins, i.e., to commence January 

1, 2021. Only the monitoring and 

reporting would be required in 2021— 

compliance with the requirement to 

hold allowances would commence on 

the compliance period schedule that is 

detailed in section V.C of this preamble. 

VI. Implementation of the Federal Plan 

and Delegation 

Under section 111(d) of the CAA, the 

EPA adopts EGs that are then 

implemented when the EPA approves a 

state or tribal 115 plan or promulgates a 

federal plan that implements and 

enforces the EGs for affected EGUs in 

states or areas of Indian country 116

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 CAA section 101(a)(3) 

and (4). Congress has also provided for 

Indian Tribes meeting specified 

eligibility criteria to implement the CAA 

within the exterior boundaries of their 

reservations or other areas within the 

tribe’s jurisdiction. See CAA section 

301(d)(1) and (2). Even in the event that 

it becomes necessary for the EPA to 

directly regulate affected EGUs under 

CAA section 111(d), states and eligible 

tribes may still seek a delegation of 

authority from the EPA to implement a 

federal plan, similar to the ability to 

take delegated authority under other 

CAA programs. The EPA encourages 

states and eligible tribes that do not 

submit approvable plans to request 

delegation of the federal plan if they 

wish to have primary responsibility for 

implementing the EGs. 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. Delegation of a standard or 

requirement generally means that 

obligations a source may have to the 

EPA under a federally promulgated 

standard become obligations to a state or 

tribe in the first instance (except for 

functions that the EPA retains for itself) 

upon delegation.117 118

A. Delegation of the Federal Plan and 

Retained Authorities 

If a state or tribe 119 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. These criteria are 

explainedgenerally in the ‘‘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, 

an inventory of the affected units’ air 

emissions, and a provision for state or 

tribal progress reports to the EPA; (3) 

certify that a public hearing has been 

held on the state or tribal delegation 

request; and (4) include a memorandum 

of agreement between the state or tribe 

and the EPA that sets forth the terms 

and conditions of the delegation, the 

effective date of the agreement and the 

mechanism to transfer authority. Upon 

signature of the agreement, the 

appropriate EPA Regional Office would 

publish an approval documentin 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 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 

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enforcement of that portion. The EPA 

will continue to hold inspection, 

information gathering, enforcement, and 

other parallel authorities along with the 

state or tribe even when a state or tribe 

has received delegation of the federal 

plan. In all cases where the federal plan 

is delegated, the EPA may retain and not 

transfer authority to a state or tribe to 

approve certain items promulgated in 

the 2015 CAA section 111(d) Clean 

Power Plan. 

This proposed federal plan also 

specifies that EGU owners or operators 

who wish to petition the agency for any 

alternative requirement should submit a 

request to the Regional Administrator 

with a copy sent 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) 

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, EPA 

delegation to a state or tribe of the 

authority to implement certain portions 

of this federal plan to the extent 

appropriate and if allowed by state or 

tribal law. Both of these options are 

described in more detail below. 

1. Federal Plan Becomes Effective Prior 

To Approval of a State or Tribal Plan 

After EGUs in a state or area of Indian 

country become subject to the federal 

plan, the state or local agency or tribe 

may still adopt and submit a plan to the 

EPA. If the EPA determines that the 

state or tribal plan is satisfactory and 

approvable pursuant to the EGs, the 

EPA will approve the state or tribal 

plan. If the EPA, on review of the 

submitted state or tribal plan, 

determines that this is not the case, the 

EPA will disapprove the plan and the 

EGUs covered in the state or tribal plan 

would remain subject to the federal plan 

until a state or tribal plan covering those 

EGUs is approved and effective. Prior to 

disapproval, the EPA will work with 

states and eligible tribes to attempt to 

reconcile areas of the plan that are 

unapprovable. 

Upon the effective date of an 

approved state or tribal plan, the federal 

plan would no longer apply to EGUs 

covered by such a plan and the state or 

local agency, or the tribe, would 

implement and enforce the state or 

tribal plan in lieu of the federal plan. 

The timing of effectiveness of an 

approved state or tribal plan in this 

circumstance may depend in part on the 

need to ensure a smooth transition and 

maintain regulatory certainty. Thus, for 

example, under a mass-based federal 

plan, we propose to handle these 

transitions so that they coincide with 

the compliance periods. The approval of 

a state or tribal plan would also involve 

a public comment process, which would 

give interested stakeholders including 

any affected EGUs, the opportunity to 

comment. This will assist in ensuring 

that compliance, program integrity, 

electric reliability, and other critical 

factors are maintained. When an EPA 

Regional Office approves a state or tribal 

plan, it will amend the appropriate 

subpart of 40 CFR part 62 or 40 CFR part 

49, respectively, to indicate such 

approval, as well as the timing of its 

effectiveness. 

As discussed elsewhere in this 

document, the EPA may also in certain 

circumstances approve a partial state or 

tribal plan (sometimes called an 

‘‘abbreviated state plan’’) that may 

modify certain limited provisions in the 

federal plan trading program. For 

example, this could occur if a state or 

tribe wishes to handle the initial 

allocation of allowances in a mass-based 

trading program, as discussed in section 

V.E of this preamble. The partial state or 

tribal plan would allow for the state or 

tribe to assume direct authority for 

administering and implementing this 

aspect of the trading program, while the 

remainder of the federal plan remains in 

place. The procedural and submission 

requirements set forth in the framework 

regulations of 40 CFR part 60, subpart 

B and the EGs would generally apply to 

a partial state or tribal plan, just as they 

would a full state or tribal plan. The 

scope of the requirement, however, 

would be commensurate with the scope 

of the partial plan. For instance, if a 

state or tribe seeks approval of a partial 

plan solely to handle allowance 

allocations, then the required statement 

of legal authority would be limited to 

those legal authorities the state or tribe 

must have to implement and enforce 

this component of the trading program. 

2. State or Tribe Takes Delegation of the 

Federal Plan 

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 appropriate 

Regional Administrator. Section II.B of 

this preamble includes Table 2 that lists 

names and addresses of the EPA 

Regional Office contacts and the states 

they cover. 

With respect to the administration of 

a federal trading program in any final 

federal plan for a state or tribe, group of 

states or combined group of states and 

tribes, the Office of Air and Radiation 

within the Headquarters of the EPA is 

proposed to be the primary office within 

the agency with delegated CAA section 

111(d)(2) authority. See Delegation 7– 

139, section 3(c). 

D. Necessary or Appropriate Finding for 

Affected EGUs in Indian Country 

Indian Tribes may, but are not 

required to, submit tribal plans to 

implement the EGs. Section 301(d) of 

the CAA and 40 CFR part 49 authorize 

the Administrator to treat an Indian 

Tribe in the same manner as a state (i.e., 

TAS) for purposes of developing and 

implementing a tribal plan 

implementing the EGs. See 40 CFR 49.3; 

see also ‘‘Indian Tribes: Air Quality 

Planning and Management,’’ hereafter 

‘‘Tribal Authority Rule,’’ (63 FR 7254, 

February 12, 1998). We invite tribes 

with EGU in their area of Indian country 

to comment on the level of their 

interest, if any, in developing their own 

plans. 

The EPA is proposing in this action to 

find that it is necessary or appropriate 

to regulate affected EGUs in each of the 

three areas of Indian country that have 

affected EGUs under the proposed 

federal plan. The EPA is authorized to 

directly implement the EGs in Indian 

country when it finds, consistent with 

the authority of CAA section 301 which 

the EPA has exercised in 40 CFR 49.11, 

that it is necessary or appropriate to do 

so. In the final EGs, the EPA establishes 

emission performance rates for the four 

EGUs located in Indian country and 

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mass- and rate-based emission goals for 

each of the three affected areas of Indian 

country. These areas include lands of 

the Navajo Nation’s reservation, lands of 

the Ute Tribe of the Uintah and Ouray 

Reservation, and lands of the Fort 

Mojave Tribe’s reservation. The EPA 

proposed carbon pollution EGs for EGUs 

in these areas and U.S. Territories in a 

Supplemental Notice of Proposed 

Rulemaking. See 79 FR 65482 

(November 4, 2014). The four facilities 

with affected EGUs located in Indian 

country that the EPA identified in the 

Supplemental Notice are: The South 

Point Energy Center, on the Fort Mojave 

Reservation geographically located 

within Arizona; the Navajo Generating 

Station, on the Navajo Indian 

Reservation geographically located 

within Arizona; the Four Corners Power 

Plant, on the Navajo Indian Reservation 

geographically located within New 

Mexico; and the Bonanza Power Plant, 

on the Uintah and Ouray Indian 

Reservation geographically located 

within Utah. The emission performance 

targets for these areas were finalized 

along with those for EGUs located in the 

rest of the country in the final EGs. 

In this action, we are proposing to 

find that it is necessary or appropriate, 

in each of the three areas of Indian 

country that have affected EGUs, to 

establish a federal plan that applies to 

the four power plants located on the 

Navajo Nation, the Fort Mojave Indian 

Reservation, and the Uintah and Ouray 

Reservation of the Ute Tribe. The 

affected EGUs located on the Navajo 

Nation are in an area of Indian country 

located within the continental United 

States, are interconnected with the 

western electricity grid, and are owned 

and operated by entities that generate 

and provide electricity to customers in 

several states. The affected EGU located 

on the Uintah and Ouray Reservation of 

the Ute Tribe is in an area of Indian 

country located within the continental 

United States, is interconnected with 

the western electricity grid, and is 

owned and operated by an entity that 

generates and provides electricity to 

customers in several states. The affected 

EGU located on the Fort Mojave Indian 

Reservation is in an area of Indian 

country located within the continental 

United States, is interconnected with 

the western electricity grid, and is 

owned and operated by an entity that 

generates and provides electricity to 

customers in several states. To date, 

none of the three tribes on whose areas 

of Indian country the four power plants 

are located have expressed a clear intent 

to develop and seek approval of a tribal 

implementation plan. Thus, absent a 

federal plan, the significant emissions 

from these four power plants could go 

unregulated by the Clean Power Plan. 

Because the agency has finalized 

emission performance targets for these 

power plants in the EGs, there is, in our 

view, little benefit to be had by not 

proposing to include them in a federal 

plan now and a potentially significant 

downside to not doing so; the 

reductions the EPA has determined are 

achievable in the EGs would become 

more difficult and costly for these 

power plants to achieve if they are 

delayed in entering into the trading 

program the agency intends to establish. 

In order to meet the performance targets, 

we are anticipating that the affected 

EGUs may need to secure allowances or 

ERCs (depending on the approach 

ultimately finalized) during the 

compliance periods. They may also be 

able to generate and sell compliance 

instruments by participating in the 

trading program. Thus, proposing a 

finding that it is necessary or 

appropriate to establish one or more 

federal plans providing the ability to 

participate in a rate- or mass-based 

trading program is in the interest of 

these four power plants located in areas 

of Indian country. We believe that this 

together with the facts that, as indicated 

above, all four EGU are interconnected 

with the western electricity grid and are 

owned and operated by an entity that 

generates and provides electricity to 

customers in several states thereby 

making it potentially disruptive and 

inequitable not to include them in one 

or more federal plans on the same 

schedule as other affected EGU strongly 

supports proposing to find that it is 

necessary or appropriate to establish 

one or more applicable federal plans at 

this time. 

We recognize that the governments of 

these tribes may still choose to seek 

TAS to develop a tribal plan, and this 

proposed determination does not 

preclude the tribes from taking such 

actions. We also note that this proposed 

determination does not preclude these 

tribes from seeking TAS and receiving 

delegation to administer aspects of any 

applicable federal plan that is ultimately 

promulgated. In the event a federal plan 

is needed, proposing a necessary or 

appropriate finding at this time will 

allow the EPA to expeditiously 

promulgate a final federal plan for one 

or all of these power plants in the future 

to allow trading to occur. We will 

continue to consult with the 

governments of the Navajo Nation, Fort 

Mojave Indian Tribe, and the Ute Tribe 

of the Uintah and Ouray Reservation 

during the comment period for this 

proposal, and prior to taking any action 

to finalize a necessary or appropriate 

finding and/or a federal plan. Comments 

on the appropriateness of the proposed 

finding should be submitted within the 

comment period specified in the DATES

section of this preamble. 

VII. Amendments To Process for 

Submittal and Approval of State Plans 

and EPA Actions 

As indicated in the final rulemaking 

action for the CAA section 111(d) 

guideline, ‘‘Carbon Pollution Emission 

Guidelines for Existing Stationary 

Sources: Electric Utility Generating 

Units,’’ in this action, in addition to the 

proposed federal plans and model 

trading rules, the EPA is also proposing 

to amend the framework regulations and 

update the process for acting on CAA 

section 111(d) state plans under 40 CFR 

part 60, subpart B. These changes would 

be applicable to any future CAA section 

111(d) rules going forward, not just the 

Clean Power Plan EGs. The EPA 

proposes six changes to the CAA section 

111(d) process in the framework 

regulations to include: (1) Partial 

approval/disapproval mechanisms 

similar to CAA section 110(k)(3); (2) a 

conditional approval mechanism similar 

to CAA section 110(k)(4); (3) a 

mechanism for the EPA to make calls for 

plan revisions similar to the ‘‘SIP-call’’ 

provisions of CAA section 110(k)(5); (4) 

an error correction mechanism similar 

to CAA section 110(k)(6); (5) 

completeness criteria and a process for 

determining completeness of state plans 

and submittals similar to CAA section 

110(k)(1) and (2); and (6) updates to the 

deadlines for the EPA action. In 

addition, in this section, the agency is 

proposing an interpretation regarding 

the effect under section 111 if an 

existing facility subject to CAA section 

111(d) modifies or reconstructs. We 

believe these changes will significantly 

streamline the state plan review and 

approval process, be more respectful of 

state processes, and generally enhance 

the administration of the CAA section 

111(d) program. 

CAA section 111(d)(1) provides that 

the EPA ‘‘shall establish a procedure 

similar to that provided by CAA section 

[110] of this title under which each state 

shall submit to the Administrator a 

[111(d)] plan. . . .’’ 42 U.S.C. 

7411(d)(1). Thus, the CAA directs the 

EPA to look to the structure of the SIP 

program when designing the procedures 

the states and agency will use to 

develop CAA section 111(d) plans. 

Notably, the CAA does not require the 

CAA section 111(d) procedures to be 

identical to those the EPA uses under 

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120See Webster’s II New Riverside University 

Dictionary (Riverside 1988) (defining ‘‘similar’’ to 

mean ‘‘resembling though not completely 

identical’’). 

121We recognize that the regulations appear to 

already contemplate partial approval/disapprovals 

to some extent. See 40 CFR 60.27(a) (‘‘The 

Administrator may . . . extend the period for 

submission of any plan . . . or portion thereof.’’) 

(emphasis added). We note that this language only 

allows for extensions of time with respect to 

portions of state plan submissions and may not 

sufficiently authorize a permanent partial approval. 

The proposed enhancement will resolve any 

ambiguity that partial approvals/disapprovals are 

an acceptable mechanism under CAA section 

111(d). 

CAA section 110 for SIPs.120 Therefore, 

the EPA interprets CAA section 111(d) 

to provide the EPA flexibility in 

designing procedures that reflect the 

structure of those used under CAA 

section 110 for implementation plans, 

without requiring the EPA to exactly 

track SIP procedures when acting on 

section 111(d) plans. 

As a general matter these proposed 

changes would simply update the CAA 

section 111(d) framework regulations to 

include several new, more flexible 

procedural tools that Congress 

introduced into section 110 in the 1990 

CAA Amendments. The basic 

procedures in the CAA section 111(d) 

framework regulations were 

promulgated in 1975 based on the 

structure of CAA section 110 as 

Congress designed it in the 1970 CAA. 

See 40 FR 53340–49 (November 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 two 

choices—to approve or disapprove SIP 

submittals. The agency struggled to deal 

responsively to situations where the 

EPA wanted to work with states to get 

state programs approved to the extent 

possible, while maintaining consistency 

with CAA requirements. Congress 

responded in 1990 and enhanced the 

procedural mechanisms the EPA has to 

act on SIPs. The EPA is proposing 

correspondingly to update the CAA 

section 111(d) regulations in a similar 

fashion. Currently, the EPA’s framework 

regulations for submittal and adoption 

of CAA section 111(d) state plans do not 

explicitly provide for the EPA to use 

some of the same procedures for 

approving or disapproving state plans 

Congress introduced into the SIP 

program in the 1990 CAA Amendments. 

The EPA is proposing to amend the 

procedures for approval or disapproval 

of CAA section 111(d) state plans to 

reflect the enhancements Congress 

included in CAA section 110 for agency 

actions on SIPs. These proposed 

amendments are discussed in more 

detail below. 

A. Partial Approvals/Disapprovals 

First, the EPA proposes to add 

authority similar to that under CAA 

section 110(k)(3) to partially approve or 

disapprove a plan.121 This is a 

particularly useful function when much 

of a state plan is approvable and the 

EPA and the state cannot reach 

resolution on only a small, severable 

portion of the state plan. In this case, 

the EPA prefers not to be in a position 

where it must disapprove the full plan, 

but rather to allow the state to move 

forward with those portions of the plan 

that are approvable. This approach 

would also address those situations 

where the state wishes to take over a 

discrete part of a federal plan. For 

instance, in this proposal, states will be 

able to seek approval of a partial state 

plan that will give them the ability to 

handle the allocation of allowances 

under a mass-based federal plan. 

In cases where elements of a plan are 

functionally severable from each other, 

and one element is approvable while 

another is not, this provision will 

authorize the EPA to approve one part 

of a plan and disapprove the other. It 

will also authorize the EPA to accept 

and review a state plan that is only 

partial in nature, if identified by the 

state as such, so long as the other 

applicable submission requirements are 

met (such as demonstration of legal 

authority and completion of the public 

process). When the state submits what 

it intends to be a full state plan (rather 

than just a partial plan), the EPA 

proposes that the approvable portion of 

a plan must be functionally severable 

from the rest of the plan. This will be 

the case when the following conditions 

are met. First, the approvable portion of 

the plan must not depend on the rest of 

the plan. In other words, the 

disapproval of the remaining portion of 

the plan must not affect the portion that 

is approved. Second, approval of the 

approvable portion must not alter the 

function of the submittal in a way that 

is contrary to the state’s intent. 

The partial disapproval would be a 

disapproval for the purposes of CAA 

section 111(d)(2)(A) and would trigger 

the EPA’s authority to issue a federal 

plan for the state, at least for that part 

of the plan that was disapproved. 

Incorporating this mechanism under the 

framework regulations for CAA section 

111(d) will enable the EPA to approve 

a state to implement as much of its 

program as is consistent with a CAA 

section 111(d) guideline and may 

reduce the scope of any federal plan that 

would be necessary. 

B. Conditional Approvals 

The second mechanism is the 

authority under CAA section 110(k)(4) 

to conditionally approve a plan. Where 

a state has submitted a plan that 

substantially meets the requirements of 

a CAA section 111(d) emission 

guideline, but requires some specific 

amendments to make it fully 

approvable, this provision authorizes 

the EPA to conditionally approve the 

plan. The Governor or his/her designee 

must submit to the EPA a commitment 

that specifies the amendments to be 

adopted and submitted to the EPA by no 

later than 1 year from the effective date 

of the conditional approval. If the state 

fails to meet its commitment, the 

conditional approval is treated as a 

disapproval. Incorporating this 

mechanism under the framework 

regulations for CAA section 111(d) will 

enable the EPA to approve a state to 

begin to administer a substantially 

complete program that requires only 

specific changes to be fully approvable. 

This provision is designed to authorize 

a state with a substantially complete 

and approvable program to begin 

implementing it, while promptly 

amending the program to ensure it fully 

complies with CAA section 111(d). 

C. Calls for Plan Revisions 

CAA section 110(k)(5) authorizes the 

EPA to find that a SIP does not comply 

with the requirements of the CAA. To 

date, the EPA has not considered using 

a similar procedure pursuant to the 

authority under CAA section 111(d). We 

now propose to do so. The ability to call 

for plan revisions is fundamental to a 

program that will be implemented over 

many years or multiple decades. Under 

the Clean Power Plan EGs, states have 

more than a decade to fully implement 

emissions standards or state measures in 

order to ensure affected EGUs achieve 

the emission goals of the EGs. 

Throughout this period, the EPA and 

the states will be monitoring their 

programs to ensure they are achieving 

the intended results. It is possible that 

design assumptions about the effect of 

control measures the states incorporate 

into their plans could prove inaccurate 

in retrospect and could result over time 

in the plan not meeting the emission 

reductions required by the EGs. In that 

case, having a procedural mechanism 

available under CAA section 111(d) 

similar to the so-called ‘‘SIP call’’ 

mechanism in CAA section 110(k)(5) 

will allow the agency to initiate a 

process with the state to make necessary 

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122Consistent with the agency’s practice under 

CAA section 110(k)(5), the EPA anticipates that a 

call for plan revisions under CAA section 111(d) 

will be done via notice and comment rulemaking. 

revisions to ensure the plan functions 

properly. 

Accordingly, the EPA is proposing to 

amend the framework regulations to 

include a provision similar to CAA 

section 110(k)(5) under which the EPA 

may find that a state’s CAA section 

111(d) plan is substantially inadequate 

to comply with the requirements of the 

CAA and require the state to revise the 

plan as necessary to correct such 

inadequacies. Consistent with CAA 

section 110(k)(5), the EPA shall notify 

the state of any inadequacies and 

establish a reasonable deadline for the 

state to submit required plan revisions. 

That deadline will not exceed 18 

months after the date of the action. The 

EPA will make its finding and notice to 

the state available to the public.122

The effect of such a finding is that 

either the state submits the program 

corrections by the date the EPA sets in 

the document, or pursuant to CAA 

section 111(d)(2)(A), the EPA has 

authority to issue a federal plan for a 

state that misses its deadline to correct 

its plan. In effect, the finding of plan 

inadequacy establishes a plan submittal 

deadline subject to the provisions of 

CAA section 111(d)(2)(A). A finding of 

failure to meet that new deadline 

triggers the EPA’s authority to issue a 

federal plan for the state. The EPA may 

promulgate a federal plan at any time 

following the state’s failure to timely 

submit an adequate plan that addresses 

the EPA’s finding. 

While these authorities are important, 

the intention of having a mechanism to 

call for plan revisions is to have a way 

to initiate an orderly process to improve 

plans when they are not meeting 

program objectives. It is the EPA’s hope 

that a call for plan revision leads to a 

constructive dialogue with a state or 

states, and ultimately, an improved and 

more effective CAA section 111(d) plan. 

The EPA is also proposing that the 

agency can call for a plan revision in 

circumstances where a state is not 

implementing its approved state plan 

and, therefore, the state plan is 

substantially inadequate to provide for 

the implementation of CAA section 

111(d) standards of performance. As 

discussed above, the CAA directs the 

EPA to develop a procedure for state 

plans under CAA section 111(d) similar 

to CAA section 110 SIP procedures. 

Calling a plan that is substantially 

inadequate to provide for 

implementation of standards of 

performance (i.e., there is a failure to 

implement a state plan) is one area 

where the EPA proposes it is 

appropriate to adapt the procedural 

mechanisms available in the SIP 

program to provide a similar process 

that assures effective state plan 

implementation under CAA section 

111(d). Under CAA section 110(k)(5), 

the EPA may call for a revision of a state 

plan ‘‘[w]henever the Administrator 

finds that the . . . plan . . . is 

substantially inadequate to . . . comply 

with any requirement of [the Act].’’ If 

the state does not submit a plan revision 

in response to the call to cure the failure 

to provide for implementation, the EPA 

would have the authority to promulgate 

the federal plan being proposed. 

One critical requirement of CAA 

section 111(d)(1)(B) is that a state must 

submit a plan that ‘‘provides for the 

implementation and enforcement of 

such standards of performance’’ 

(emphasis added). If, after the EPA has 

approved a plan, a state fails to 

implement that plan, the plan has 

become substantially inadequate to 

comply with this requirement of the 

CAA. Under this proposal, the EPA’s 

remedy would be to find the plan is 

substantially inadequate, which triggers 

the state’s obligation to cure, and failing 

that, the EPA’s authority to promulgate 

the federal plan. 

In the alternative, the EPA proposes 

that this authority to call a plan for 

failure to implement is anchored in the 

authority provided under CAA section 

110(k)(5) to call a SIP when the agency 

finds that it is ‘‘substantially inadequate 

to attain or maintain the relevant 

national ambient air quality standard.’’ 

In the context of CAA section 111, this 

authority translates into the EPA calling 

a state plan when the agency finds that 

it is substantially inadequate to achieve 

the emission reductions required under 

the EGs. 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 emission reductions 

required under the EGs. The state’s 

failure to implement has revised the 

effect of the plan so that it is no longer 

adequate to meet the CAA’s 

requirements. 

D. Error Corrections 

The fourth mechanism is the error 

correction authority under CAA section 

110(k)(6). Where the EPA concludes that 

it has erroneously approved, 

disapproved, or promulgated a plan or 

plan revision (or part thereof), this 

section authorizes the agency to revise 

its action, in the same manner as the 

original action, without requiring any 

further submission from the state. Prior 

to the 1990 CAA Amendments, there 

was some question whether the EPA 

could unilaterally correct a previous 

action on a SIP submittal without the 

state having to submit a new SIP. This 

limitation imposed unnecessary 

burdens on states to fix even obvious 

errors, because CAA section 110(a)(2) 

requires the state to provide notice and 

a public hearing on each new SIP 

submittal. Incorporating this mechanism 

into the CAA section 111(d) framework 

regulations will allow the EPA to fix 

errors in its prior actions on state plans 

without imposing on the states the 

corresponding burden of providing 

notice and a public hearing as required 

under the CAA section 111(d) 

framework regulations. See 40 CFR 

60.23. 

E. Completeness Criteria 

Completeness criteria provide the 

agency with a means to determine 

whether a submission by a state 

includes the minimum elements that 

must be met before the EPA is required 

to act on such submission. When 

submittals do not contain the necessary 

minimum elements, then the EPA may, 

without further action, find that a state 

has failed to submit a plan. This 

determination is ministerial in nature 

and requires no exercise of discretion or 

judgment on the agency’s part, nor does 

it reflect a judgment on the sufficiency 

or adequacy of the submitted portions of 

a state plan. The task is accomplished 

by simply comparing the materials 

provided by the state as its submittal 

against the required criteria to 

determine whether the plan is complete 

or not. In the case of SIPs under CAA 

section 110(k)(1), the EPA promulgated 

completeness criteria in 1990 at 

Appendix V to 40 CFR part 51 (55 FR 

5830; February 16, 1990). The EPA 

proposes to adopt criteria similar to the 

criteria set out at section 2.0 of 

Appendix V for determining the 

completeness of submissions under 

CAA section 111(d). The completeness 

criteria can be grouped into: (1) 

Administrative materials; and (2) 

technical support. The EPA proposes 

that both groups would apply to all 

CAA section 111(d) rules going forward. 

The agency notes that the addition of 

completeness criteria in the framework 

regulations does not alter any of the 

submission requirements states already 

have under the EGs. 

For administrative materials, the EPA 

is proposing completeness criteria that 

mirror the existing administrative 

criteria for SIP submittals because the 

two programs have similar 

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administrative processes. The EPA 

proposes that a complete final state plan 

submittal under CAA section 111(d) 

must include: (1) A formal letter of 

submittal from the Governor or his/her 

designee requesting EPA approval of the 

plan or revision thereof; (2) evidence 

that the state has adopted the plan in the 

state code or body of regulations (That 

evidence must include the date of 

adoption or final issuance as well as the 

effective date of the plan, if different 

from the adoption/issuance date.); (3) 

evidence that the state has the necessary 

legal authority under state law to adopt 

and implement the plan; (4) a copy of 

the actual regulation, or document 

submitted for approval and 

incorporation by reference into the plan. 

The submittal must 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 must, 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 

must indicate the changes made (for 

example, by redline/strikethrough) to 

the approved plan.); (5) evidence that 

the state followed all of the procedural 

requirements of the state’s laws and 

constitution in conducting and 

completing the adoption/issuance of the 

plan; (6) evidence that public notice was 

given of the proposed change with 

procedures consistent with the 

requirements of 40 CFR 60.23, including 

the date of publication of such notice; 

(7) certification that public hearing(s) 

were held in accordance with the 

information provided in the public 

notice and the state’s laws and 

constitution, if applicable and 

consistent with the public hearing 

requirements in 40 CFR 60.23; and (8) 

compilation of public comments and the 

state’s response thereto. 

These criteria, as proposed, are 

intended to be generic to all CAA 

section 111(d) plans going forward, with 

the proviso that specific EGs may 

provide otherwise. The technical 

support completeness criteria that the 

EPA proposes will also be generic to all 

CAA section 111(d) rules, with the same 

proviso. The EPA proposes that the 

technical support required for all plans 

must include each of the following: (1) 

Description of the plan approach and 

geographic scope; (2) identification of 

each designated facility, identification 

of emission standards for each 

designated facility, and monitoring, 

recordkeeping, and reporting 

requirements that will determine 

compliance by each designated facility; 

(3) identification of compliance 

schedules and/or increments of 

progress; (4) demonstration that the 

state plan submittal is projected to 

achieve emissions performance under 

the applicable EGs; (5) documentation 

of state recordkeeping and reporting 

requirements to determine the 

performance of the plan as a whole; and 

(6) demonstration that each emission 

standard is quantifiable, nonduplicative, permanent, verifiable, and 

enforceable. 

The EPA proposes a process similar, 

though not identical, to that set forth in 

40 CFR 51.103 and Appendix V to 40 

CFR part 51 to make completeness 

determinations. Similar to CAA section 

110(k)(1)(C), under this proposal, where 

the EPA determines that a state 

submission required under CAA section 

111(d) does not meet the minimum 

completeness criteria we are proposing 

to establish, the state will be considered 

to have not made the submission. The 

EPA further proposes that, similar to 

CAA section 110(k)(1)(B), within 60 

days of the EPA’s receipt of a state 

submission, but no later than 6 months 

after the date, if any, by which a state 

is required to submit the plan or 

revision, the Administrator shall 

determine whether the minimum 

criteria have been met. Any plan or plan 

revision that a state submits to the EPA, 

and that has not been determined by the 

EPA by the date 6 months after receipt 

of the submission to have failed to meet 

the minimum criteria, shall on that date 

be deemed by operation of law to meet 

such minimum criteria. In cases where 

a state does not submit anything to the 

agency, however, the Administrator 

must make a finding of failure to submit 

no later than 6 months after the date, if 

any, by which a state is required to 

submit the plan or revision. (In other 

words, ‘‘completeness by operation of 

law’’ is only available where the state 

has actually submitted a plan to the 

agency.) 

As with the completeness 

determination process for SIP 

submissions, the EPA’s determination 

that a submittal is complete is not a 

finding that the submittal meets the 

substantive requirements of CAA 

section 111(d) or the guideline. That 

must be done via the process for 

approval or disapproval of a state plan, 

which would be done through notice 

and comment rulemaking. In the 

completeness process, the EPA will 

confirm that a state’s submittal appears 

to have addressed the criteria for a 

complete submittal and, therefore, the 

submittal is sufficient to trigger the 

EPA’s obligation to act on it. But in the 

completeness process the agency will 

not assess the content of those 

submissions to determine if they are 

approvable. Accordingly, even when the 

EPA affirmatively determines that a 

submittal is complete, it does not 

prevent the agency from later finding 

that the state plan does not meet the 

requirements of the EGs, including 

finding that the submittal failed to 

address a required element and must be 

disapproved. 

Similarly, when a submittal is 

determined to be complete by operation 

of law after 6 months without the EPA’s 

affirmative determination of 

completeness, the only legal 

consequence is that the EPA now has an 

obligation to act on that submittal. 

Completeness by operation of law 

means that the submittal is deemed 

complete and requires the EPA’s review, 

whether or not the state has actually 

addressed all the required elements. 

Accordingly, if the agency determines 

that a state has failed to address a 

required element in its submittal once 

the EPA begins review of the state plan 

that is complete by operation of law, the 

agency must go through the process of 

disapproving (or partially disapproving 

or conditionally approving, as discussed 

below) that plan, unless the state and 

the EPA work together to cure the 

deficiency. In other words, the EPA 

cannot simply find the plan incomplete 

and return it to the state at that point. 

But the finding of completeness by 

operation of law in no way prevents the 

EPA from subsequently concluding that 

the state’s submission is missing a 

required element of the program and 

making that finding as part of a 

disapproval of the plan. 

As described in the final rulemaking 

action for the CAA section 111(d) EGs, 

a state will submit all CAA section 

111(d) plans electronically. If the EPA 

determines that any submission fails to 

meet the completeness criteria, the 

agency may return the plan to the state 

and request corrections, identifying the 

components that are absent or 

insufficient to allow the EPA to perform 

a review of the plan. The state will not 

have met its obligation to submit a final 

plan until it resubmits a revised state 

plan or supporting materials addressing 

the corrections the EPA identified in its 

incompleteness determination. 

The EPA is also proposing to include 

an exception to the criteria for complete 

administrative materials in cases where 

a state and the EPA are ‘‘parallel 

processing’’ the final plan. Parallel 

processing allows a state to submit the 

plan prior to final adoption by the state 

and provides an opportunity for the 

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123As under CAA section 110, the EPA believes 

that, should it fail for whatever reason to meet a 

deadline by which it was to take action, such as 

issue a federal plan, under CAA section 111(d), that 

failure does not thereby obviate or in any way 

remove the EPA’s authority or obligation to take 

that action. See Oklahoma v. U.S. EPA, 723 F.3d 

1201, 1224 (10th Cir. 2013) (‘‘Although the statute 

undoubtedly requires that the EPA promulgate a 

FIP within two years, it does not stand to reason 

that it loses its ability to do so after this two-year 

period expires. Rather, the appropriate remedy 

when the EPA violates the statute is an order 

compelling agency action.’’). 

state to consider the EPA’s comments 

prior to submission of a final plan for 

final review and action. The EPA would 

propose to take action on a state plan 

based on a proposed state regulation. 

The EPA would only finalize the action 

if the state adopts a final plan that is 

legally effective under state law. The 

EPA would only approve the plan if the 

state addressed any corrections that the 

EPA identified in its proposed action on 

the state plan without any other 

material change to the plan. Note that a 

plan submitted for parallel processing 

must still meet all the criteria for 

technical completeness so that the EPA 

and the public have a sufficient basis on 

which to evaluate and comment on the 

EPA’s proposed action. 

F. Update to Deadlines for EPA Actions 

The EPA proposes to update the 

deadlines for acting on state submittals 

and promulgating a federal plan under 

40 CFR 60.27(b), (c), and (d) to more 

closely track the current versions of 

CAA sections 110(c) and 110(k) adopted 

in 1990. The framework regulations for 

CAA section 111(d) state plans currently 

are parallel to the prior version of CAA 

section 110. They require the EPA to act 

on a state plan or plan revision 

submittal within 4 months after the date 

required for submission of a plan or 

plan revision. See 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, see 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, see 40 CFR 

60.27(d). 

The final CO2 EGs for affected EGUs 

have already adjusted the deadline in 40 

CFR 60.27(b) to require the EPA to act 

on a state plan under those EGs within 

12 months (rather than 4 months) after 

the date required for submission of a 

plan. See 40 CFR 60.5715. However, the 

Clean Power Plan EGs did not modify 

the 6-month deadline for a federal plan 

in 40 CFR 60.27(d). 

The EPA is proposing to amend 40 

CFR 60.27(b) to allow the EPA 12 

months to approve or disapprove 

submittals of all plans or plan revisions 

under CAA section 111(d), not just 

those related to the Clean Power Plan 

under 40 CFR 60.5715. This change 

would provide the EPA with sufficient 

time for the steps required to approve or 

disapprove the submittal, which include 

proposing the EPA’s approval or 

disapproval of the plan or plan revision, 

a public comment period on the EPA’s 

proposal, time for the EPA to review 

and respond to public comments, and 

the issuance of a final rule approving or 

disapproving the plan or plan revision. 

The EPA is also proposing to amend 

40 CFR 60.27(b) to specify that the 

deadline for the EPA to act on a plan or 

plan revision is 12 months after receipt 

of a complete plan or plan revision, 

rather than 12 months after the deadline 

for submittal of a plan or plan revision. 

This amendment will allow the EPA to 

have the full 12 months to act on 

submittals of complete plans or plan 

revisions. 

The EPA also proposes slight 

modifications to the provision related to 

issuing a proposed federal plan in 40 

CFR 60.27(c); changing the 6-month 

deadline for issuing a final federal plan 

in 40 CFR 60.27(d) to 1 year; 123 and, 

similar to the change in timing for 40 

CFR 60.27(b) above, setting the deadline 

for promulgation of a federal plan to run 

from the date of the EPA’s action on a 

state submittal, rather than from the 

original deadline for a state submittal. 

The EPA believes it is appropriate to 

modify these timing requirements for 

several reasons. First, the EPA notes that 

under CAA section 111(d)(2), Congress 

gave the EPA the ‘‘same’’ authority to 

prescribe a federal plan under CAA 

section 111(d) as it would have under 

CAA section 110(c) in the case of a state 

failure to submit a SIP. The term ‘‘same’’ 

stands in contrast to the term ‘‘similar’’ 

in CAA section 111(d)(1) (discussed 

above). As with the use of the term 

‘‘similar,’’ the EPA believes it is 

authorized by this language to follow 

the timing provisions of CAA section 

110(c) as currently enacted. Second, as 

a general matter, the timing 

requirements of current 40 CFR 60.27(c) 

and (d), which effectively require the 

EPA to propose and finalize a federal 

plan within 6 months of the deadline for 

state submittals, may be outdated and 

unrealistic with respect to the timelines 

for review of state plans and the time 

periods for action, particularly as 

informed by the agency’s experience 

with CAA section 110 SIPs (which led 

to the extension of the timelines and 

other changes to CAA section 110 in the 

1990 Amendments discussed above). 

Third, in the Clean Power Plan EGs, 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 40 CFR 

60.27(d) that the EPA must promulgate 

a federal plan within 6 months of the 

initial deadline for state plans is 

therefore inconsistent with this 

provision. Fourth, existing 40 CFR 

60.27(c) tracks the prior version of CAA 

section 110(c) with respect to the 

issuance of a proposed federal plan. 

This relatively prescriptive language is 

no longer present in CAA section 110(c). 

The procedural requirements for 

rulemakings under both CAA section 

110 and 111(d) are set out in section 

307(d) of the CAA, and the EPA believes 

those provisions are appropriate and 

adequate to guide its rulemaking 

process for CAA section 111(d) federal 

plans. 

The EPA invites comment on all of 

these proposed changes to the 

framework regulations. The EPA notes 

that the addition of these mechanisms to 

the framework regulations will make 

them available for all CAA section 

111(d) regulations, not just those under 

the Clean Power Plan at 40 CFR part 60, 

subpart UUUU. 

G. Proposed Interpretation Regarding 

Existing Sources That Modify or 

Reconstruct 

In the proposed rulemaking for the 

Clean Power Plan, the EPA proposed the 

interpretation that if an existing source 

is subject to a CAA section 111(d) state 

plan, and then undertakes a 

modification or reconstruction, the 

source remains subject to the state plan, 

while also becoming subject to the 

modification or reconstruction 

requirements. See 79 FR 34830, 34903– 

4 (June 18, 2014). The EPA did not 

finalize a position on this issue in the 

final EGs rule, but indicated that it 

would re-propose and request comment 

on this issue through this federal plan 

rulemaking. The EPA also stated 

deferral of action on this issue does not 

impact states’ and affected EGUs’ 

pending obligations under the final 

Emission Guidelines relating to plan 

submission deadlines, as this issue 

concerns potential obligations or 

impacts after an existing source has 

already become subject to the 

requirements of a state plan. The EPA 

intends to finalize its position on this 

issue through this rulemaking, which 

will be well in advance of the plan 

performance period beginning in 2022, 

at which point state plan obligations on 

existing sources are effectuated. 

We noted in the Clean Power Plan 

proposal that CAA section 111(d) is 

arguably silent as to this issue. Thus, we 

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124See 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). 

took this to grant the agency the 

authority to provide a reasonable 

interpretation to fill in the gaps where 

the statute is silent. In the proposal for 

the Clean Power Plan, we proposed to 

disallow existing sources to leave the 

CAA section 111(d) program through 

modification or reconstruction. We did 

this for two reasons. First, if a source 

did so, that could prove disruptive to 

the state plan. Second, allowing sources 

to do so could provide them an 

incentive that would be contrary to the 

purposes of CAA section 111(d). We 

then asked for comment on ‘‘whether 

this interpretation is supported by the 

statutory text and whether this 

interpretation is sensible policy and will 

further the goals of the statute.’’ 

We received many comments 

disagreeing with this approach. After 

reviewing these comments, the agency 

believes an alternative interpretation is 

more appropriate in the particular 

context here. In order to give the public 

an opportunity to comment on this, we 

are proposing this interpretation here. 

That is, when CAA section 111(d) EGs 

are initially promulgated for existing 

stationary sources in response to 

corresponding CAA section 111(b) 

standards of performance for the same 

pollutant, the statute prevents new, 

modified, or reconstructed sources 

(including under those particular CAA 

section 111(b) standards of performance 

and as those terms are applied in the 

relevant new source performance 

standards (NSPS)) from simultaneously 

being subject to state plans under those 

particular CAA section 111(d) EGs. This 

interpretation gives meaning to the 

definition of ‘‘existing source’’ in CAA 

section 111(a)(6) and is consistent with 

the definition of ‘‘new source’’ in CAA 

section 111(a)(2). Further, it is 

consistent with the historical treatment 

of modified and reconstructed sources 

in the CAA section 111 program. 

The EPA notes the concerns it noted 

in the proposal supporting why the 

originally proposed interpretation was 

reasonable are being addressed in other 

ways in the final EGs, and in the 

proposed federal plan. In other words, 

there will be other ways to minimize 

disruption to state plans if such a 

modification or reconstruction were to 

take place. We invite comment on the 

agency’s proposed interpretation that 

when an existing source modifies or 

reconstructs in such a way that it meets 

the definition of a new source, for 

purposes of a particular NSPS and 

emission guideline, it becomes a new 

source under the statute and is no 

longer subject to the CAA section 111(d) 

program 

H. Separate Finalization of These 

Changes 

The agency intends to finalize these 

procedural changes and interpretation 

sooner than it finalizes the rest of this 

proposed action. The EPA believes these 

changes generally enhance and improve 

the framework regulations in a way that 

will be of benefit to the states, the EPA, 

and other stakeholders, and will 

improve the overall efficacy of the 

program. We believe it is important to 

finalize these changes to the framework 

regulations relatively quickly in order to 

provide states and other stakeholders 

predictability in how the EPA intends to 

process state plans and submissions 

under CAA section 111(d). If the EPA 

does finalize these changes sooner than 

the model trading rules or the federal 

plan, it will do so after the close of the 

comment period, and after 

consideration and response to any 

comments on these changes. 

VIII. Impacts of This Action 

A. Endangered Species Act 

Consistent with the requirements of 

section 7(a)(2) of the Endangered 

Species Act (ESA), the EPA has 

considered the effects of this proposed 

rule and has reviewed applicable ESA 

regulations, case law, and guidance to 

determine what, if any, impact there 

may be to listed endangered or 

threatened species or designated critical 

habitat. Section 7(a)(2) of the ESA 

requires federal agencies, in 

consultation with the U.S. Fish and 

Wildlife Service (FWS) and/or the 

National Marine Fisheries Service, to 

ensure that actions they authorize, fund, 

or carry out are not likely to jeopardize 

the continued existence of federally 

listed endangered or threatened species 

or result in the destruction or adverse 

modification of designated critical 

habitat of such species. See 16 U.S.C. 

1536(a)(2). Under relevant 

implementing regulations, ESA section 

7(a)(2) applies only to actions where 

there is discretionary federal 

involvement or control. See 50 CFR 

402.03. Further, under the regulations 

consultation is required only for actions 

that ‘‘may affect’’ listed species or 

designated critical habitat. See 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. See 50 CFR 

402.02. Direct effects are the direct or 

immediate effects of an action on a 

listed species or its habitat.124 Indirect 

effects are those that are caused by the 

action, later in time, and are reasonably 

certain to occur. Id. To trigger a 

consultation requirement, there must 

thus be a causal connection between the 

federal action, the effect in question, 

and if the effect is indirect, it must be 

reasonably certain to occur. 

The EPA has considered the effects of 

this proposed rule and has reviewed 

applicable ESA regulations, case law, 

and guidance to determine what, if any, 

impact there may be to listed species or 

designated critical habitat for purposes 

of ESA section 7(a)(2) consultation. The 

EPA notes that the projected 

environmental effects of this proposal 

are, like the EGs that it implements, 

positive: Reductions in overall GHG 

emissions, and reductions in PM and 

ozone-precursor emissions (sulfur 

oxides and NOX), for EGUs that will be 

covered by the federal plan. However, 

the EPA’s assessment that the rule will 

have an overall net positive 

environmental effect by virtue of 

reducing emissions of certain air 

pollutants does not address whether the 

rule may affect any listed species or 

designated critical habitat for ESA 

section 7(a)(2) purposes and does not 

constitute any finding of effects for that 

purpose. The fact that the rule will have 

overall positive effects on the national 

and global environment does not mean 

that the rule may affect any listed 

species in its habitat or the designated 

critical habitat of such species within 

the meaning of ESA section 7(a)(2) or 

the implementing regulations or require 

ESA consultation. The EPA has 

considered various types of potential 

effects in considering whether ESA 

consultation is required for this rule. 

With respect to the projected GHG 

emission reductions, the EPA does not 

believe that such reductions trigger ESA 

consultation requirements under ESA 

section 7(a)(2). In reaching this 

conclusion, the EPA is mindful of 

significant legal and technical analysis 

undertaken by FWS and the U.S. 

Department of the Interior (DOI) 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 

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65040 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Proposed Rules 

125See, 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’’ (October 3, 2008). 

126See 75 FR 25438 Table I.C 2–4 (May 7, 2010); 

77 FR at 62894 Table III–68 (October 15, 2012). 

127See 51 FR 19933 (describing effects that are 

‘‘reasonably certain to occur’’ in the context of 

consideration of cumulative effects and 

distinguishing broader consideration that may be 

appropriate in applying a procedural statute such 

as the National Environmental Policy Act, as 

opposed to a substantive provision such as ESA 

section 7(a)(2) that may prohibit certain federal 

actions); Endangered Species Consultation 

Handbook, U.S. Fish & Wildlife Service and 

National Marine Fisheries Service at 4–30 (March 

1998) (in the same context, describing indicators 

that an activity is reasonably certain to occur as 

including governmental approvals of the action or 

indications that such approval is imminent, project 

sponsors’ assurance that the action will proceed, 

obligation of venture capital, or initiation of 

contracts; and noting that the more governmental 

between GHG emissions and effects on 

the species in its habitat.125 The DOI 

Solicitor concluded that where the 

effect at issue is climate change, 

proposed actions involving GHG 

emissions cannot pass the ‘‘may affect’’ 

test of the ESA section 7 regulations 

and, thus, are not subject to ESA 

consultation. 

The EPA has also previously 

considered issues relating to GHG 

emissions in connection with the 

requirements of ESA section 7(a)(2). In 

the final EGs, the agency noted that, 

although the GHG emission reductions 

projected for the EGs are large 

(estimated reductions of about 415 

million short tons of CO2 in 2030 

relative to the base case), the EPA 

evaluated larger reductions in assessing 

this same issue in the context of the 

light duty vehicle GHG emission 

standards for model years 2012–2016 

and 2017–2025. There the agency 

projected emission reductions over the 

lifetimes of the model years in 

question,126 which are roughly five to 

six times those projected above and, 

based on air quality modeling of 

potential environmental effects, 

concluded that ‘‘EPA knows of no 

modeling tool which can link these 

small, time-attenuated changes in global 

metrics to particular effects on listed 

species in particular areas. Extrapolating 

from global metric to local effect with 

such small numbers, and accounting for 

further links in a causative chain, 

remain beyond current modeling 

capabilities.’’ EPA, Light Duty Vehicle 

Greenhouse Gas Standards and 

Corporate Average Fuel Economy 

Standards, Response to Comment 

Document for Joint Rulemaking at 4–102 

(Docket EPA–OAR–HQ–2009–4782). 

The EPA reached this conclusion after 

evaluating issues relating to potential 

improvements from the fuel efficiency 

rule relevant to both temperature and 

oceanographic pH outputs. The EPA’s 

ultimate finding was that ‘‘any potential 

for a specific impact [of the specific 

federal action] on listed species in their 

habitats associated with these very 

small changes in average global 

temperature and ocean pH is too remote 

to trigger the threshold for ESA section 

7(a)(2).’’ Id. See also, e.g., Ground Zero 

Center for Non-Violent Action v. U.S. 

Dept. of Navy, 383 F. 3d 1082, 1091–92 

(9th Cir. 2004). The EPA similarly 

proposes to determine that the 

likelihood of jeopardy to a species from 

this proposed action is extremely 

remote, and ESA does not require 

consultation. The EPA’s proposed 

conclusion is entirely consistent with 

DOI’s analysis regarding ESA 

requirements in the context of federal 

actions involving GHG emissions. 

With regard to non-GHG air 

emissions, the EPA is also projecting 

substantial reductions of SO2 and NOX

as a collateral consequence of this 

proposal (which will be, as stated above, 

only a subset of the total reductions 

from the EGs). However, CAA section 

111(d) cannot directly control emissions 

of criteria pollutants. And furthermore, 

a federal plan under CAA section 

111(d)(2) does no more than prescribe 

emissions standards of the same 

stringency as the corresponding EGs. 

See 40 CFR 60.27(e)(1). Consequently, 

CAA section 111(d) provides no 

discretion to set a standard in a federal 

plan based on potential impacts to 

endangered species of reduced criteria 

pollutant emissions. ESA section 7(a)(2) 

consultation is not required with respect 

to the projected reductions of criteria 

pollutant emissions. See 50 CFR 402.03; 

see also WildEarth Guardians v. U.S. 

Envt’l Protection Agency, 759 F.3d 1196, 

1207–10 (10th Cir. 2014) (the EPA has 

no duty to consult under section 7 of the 

ESA regarding HAP controls that it did 

not require—and likely lacked authority 

to require—in a FIP for regional haze 

controls under section 169A of the 

CAA.). 

Finally, the EPA has also considered 

other potential effects of the rule 

(beyond reductions in air pollutants) 

and whether any such effects are 

‘‘caused by’’ the rule and ‘‘reasonably 

certain to occur’’ within the meaning of 

the ESA regulatory definition of the 

effects of an action. See 50 CFR 402.02. 

The EPA recognizes, for instance, that 

questions may exist whether decisions 

such as increased utilization of solar or 

wind power could have effects on listed 

species. The EPA received comments on 

the EGs asserting that because potential 

increased reliance on wind or solar 

power may be an element of Building 

Block 3, and because wind and solar 

facilities may in some cases have effects 

on listed species, the EPA must consult 

under the ESA on this aspect of the rule. 

The EPA has carefully considered the 

comments and the correspondence from 

Congress as well as the case law and 

other materials cited in those 

documents. The EPA does not believe 

that the effects of potential future 

changes in the energy sector—including 

increased reliance on wind or solar 

power as a result of future potential 

actions by states or other implementing 

entities—or any potential alterations in 

the operations of any particular facility 

would, at the time of promulgation of a 

federal plan, be sufficiently certain to 

occur so as to require ESA consultation 

on the rule. The EPA appreciates that 

the ESA regulations call for consultation 

where actions authorized, funded, or 

carried out by federal agencies may have 

indirect effects on listed species or 

designated critical habitat. However, as 

noted above, indirect effects must be 

caused by the action at issue and must 

be reasonably certain to occur. 

Under a federal plan, it is the EPA 

that would implement a CAA section 

111(d) plan. The EPA believes that even 

with this proposed federal plan, any 

effects on listed species or designated 

habitat are too uncertain to require 

consultation under ESA section 7. This 

is so for at least two reasons: (1) The 

EPA cannot know with any certainty at 

this stage which states will actually 

become subject to a finally promulgated 

federal plan. Which affected EGUs, in 

which states, will be covered by this 

plan can only be known after states have 

failed to submit a plan, or have had 

their plans disapproved by the EPA; and 

(2) the federal plan as proposed will be 

implemented through some form of 

emissions trading. Emissions trading 

inherently provides maximum 

flexibility to individual affected EGUs to 

choose their method of compliance, 

including continuing to emit the 

relevant pollutant at historical rates so 

long as the affected EGU holds sufficient 

credits or allowances. At this point, the 

EPA has no meaningful information to 

express in any more than the broadest 

terms how any particular affected EGU 

may choose to comply with the federal 

plan, should it be promulgated for them 

based on their location in an area not 

covered by an approved state plan. The 

Services have explained that ESA 

section 7(a)(2) was not intended to 

preclude federal actions based on 

potential future speculative effects.127

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administrative discretion remains to be exercised, 

the less there is reasonable certainty the action will 

proceed). 

128 It is important to note that the differences 

between the analytical results for the rate-based and 

mass-based federal plan approaches presented may 

not be indicative of likely differences between the 

approaches. If one approach performs differently 

than the other on a given metric during a given time 

period, this does not imply this will apply in all 

instances. 

These are precisely the types of 

speculative future activities and effects 

currently at issue here. The EPA 

requests comment on its proposed 

conclusion that ESA section 7 

consultation is not required for this 

action. The EPA will continue to 

evaluate the scope and potential effects 

of federal planning activities for this 

source category to the extent federal 

plans are needed and implemented in 

specific areas and over specific sources. 

B. What are the air impacts? 

The EPA anticipates significant 

emission reductions under this 

proposed action for the utility power 

sector. 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 Clean Power Plan EGs. 

However, at the time of this proposal, 

the EPA has no information on whether 

any or how many states will require a 

federal plan or will adopt a model rule. 

Because of this lack of information, in 

the Regulatory Impact Analysis (RIA) for 

this proposal, the EPA chose to examine 

a scenario where all states of the 

contiguous United States will be 

regulated under a federal plan or will 

adopt the model rule. Additionally, we 

examine two alternative federal plan 

approach scenarios. The first federal 

plan approach assumes all states in the 

contiguous United States are regulated 

under a rate-based federal plan. The 

second federal plan approach assumes 

all contiguous states are regulated under 

a mass-based federal plan.128

Under the rate-based approach, when 

compared to 2005, CO2 emissions are 

projected to be reduced by 

approximately 22 percent in 2020, 28 

percent in 2025, and 32 percent in 2030. 

Under the mass-based approach, when 

compared to 2005, CO2 emissions are 

projected to be reduced by 

approximately 23 percent in 2020, 29 

percent in 2025, and 32 percent in 2030. 

The proposal is projected to result in 

substantial co-benefits through 

reductions of SO2, NOX, and PM2.5 that 

will have direct public health benefits 

by lowering ambient levels of these 

pollutants and ozone. Table 12 and 

Table 13 of this preamble show 

expected CO2 and other air pollutant 

emissions in the base case and 

reductions under the proposal for 2020, 

2025, and 2030 for both rate-based and 

mass-based approaches. 

TABLE 12—SUMMARY OF CO2 AND OTHER AIR POLLUTANT EMISSION REDUCTIONS FROM THE BASE CASE UNDER RATEBASED FEDERAL PLAN APPROACH

CO2

(million 

short tons) 

SO2

(thousand 

short tons) 

NOX

(thousand 

short tons) 

2020 

Base Case ................................................................................................................................... 2,155 1,311 1,333 

Rate-based Federal Plan Approach ............................................................................................ 2,085 1,297 1,282 

Emission Reductions ................................................................................................................... 69 14 50 

2025 

Base Case ................................................................................................................................... 2,165 1,275 1,302 

Rate-based Federal Plan Approach ............................................................................................ 1,933 1,097 1,138 

Emission Reductions ................................................................................................................... 232 178 165 

2030 

Base Case ................................................................................................................................... 2,227 1,314 1,293 

Rate-based Federal Plan Approach ............................................................................................ 1,812 996 1,011 

Emission Reductions ................................................................................................................... 415 318 282 

Source: Integrated Planning Model, 2015. 

Note: Emissions may not sum due to rounding. 

TABLE 13—SUMMARY OF CO2 AND OTHER AIR POLLUTANT EMISSION REDUCTIONS FROM THE BASE CASE UNDER MASSBASED FEDERAL PLAN APPROACH

CO2

(million 

short tons) 

SO2

(thousand 

short tons) 

NOX

(thousand 

short tons) 

2020 

Base Case ................................................................................................................................... 2,155 1,311 1,333 

Mass-based Federal Plan Approach ........................................................................................... 2,073 1,257 1,272 

Emission Reductions ................................................................................................................... 81 54 60 

2025 

Base Case ................................................................................................................................... 2,165 1,275 1,302 

Mass-based Federal Plan Approach ........................................................................................... 1,901 1,090 1,100 

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TABLE 13—SUMMARY OF CO2 AND OTHER AIR POLLUTANT EMISSION REDUCTIONS FROM THE BASE CASE UNDER MASSBASED FEDERAL PLAN APPROACH—Continued 

CO2

(million 

short tons) 

SO2

(thousand 

short tons) 

NOX

(thousand 

short tons) 

Emission Reductions ................................................................................................................... 265 185 203 

2030 

Base Case ................................................................................................................................... 2,227 1,314 1,293 

Mass-based Federal Plan Approach ........................................................................................... 1,814 1,034 1,015 

Emission Reductions ................................................................................................................... 413 280 278 

Source: Integrated Planning Model, 2015. 

Note: Emissions may not sum due to rounding. 

The reductions in Tables 12 and 13 of 

this preamble do not account for 

reductions in HAP that may occur as a 

result of this rule. For instance, the fine 

particulate reductions presented above 

do not reflect all of the reductions in 

many heavy metal particulates. 

C. What are the energy impacts? 

The proposed action may have 

important energy market implications. 

Table 14 of this preamble presents a 

variety of important energy market 

impacts for 2020, 2025, and 2030 under 

both the rate-based and mass-based 

federal plan approaches described in 

section VIII.B of this preamble and 

presented in the RIA for this proposal. 

TABLE 14—SUMMARY TABLE OF IMPORTANT ENERGY MARKET IMPACTS FOR RATE-BASED AND MASS-BASED FEDERAL

PLAN APPROACHES

[Percent change from base case] 

Rate-Based Mass-Based 

2020 2025 2030 2020 2025 2030 

Retail electricity prices ..................................................................................................... 3% 1% 1% 3% 2% 0% 

Average electricity bills .................................................................................................... 3 ¥4 ¥7 2 ¥3 ¥8 

Price of coal at minemouth .............................................................................................. ¥1 ¥5 ¥4 ¥1 ¥5 ¥3 

Coal production for power sector use ............................................................................. ¥5 ¥14 ¥25 ¥7 ¥17 ¥24 

Price of natural gas delivered to power sector ................................................................ 5 ¥8 2 4 ¥3 ¥2 

Natural gas use for electricity generation ........................................................................ 3 ¥1 ¥1 5 0 ¥4 

These figures reflect the EPA’s 

modeling that presumes policies that 

lead to generation shifts and growing 

use of DS–EE and renewable electricity 

generation out to 2029. If different 

implementation choices are made than 

those modeled, impacts could be 

different. 

D. What are the compliance costs? 

The compliance costs of this proposed 

action are represented in this analysis as 

the change in electric power generation 

costs between the base case and 

modeled federal plan approaches 

described in section VIII.B of this 

preamble and presented in the RIA for 

this proposal. The incremental cost is 

the projected additional cost of 

complying with the proposed action in 

the year analyzed and includes the 

amortized cost of capital investment, 

needed new capacity, shifts between or 

among various fuels, deployment of DS– 

EE programs, and other actions 

associated with compliance. These 

important dynamics are discussed in 

more detail in the RIA in the rulemaking 

docket. 

The EPA estimates the annual 

incremental compliance cost for the 

rate-based federal plan approach to be 

$2.5 billion in 2020, $1.0 billion in 2025 

and $8.4 billion in 2030. The EPA 

estimates the annual incremental 

compliance cost for the mass-based 

federal plan approach to be $1.4 billion 

in 2020, $3.0 billion in 2025, and $5.1 

billion in 2030. More detailed cost 

estimates are available in the RIA in the 

rulemaking docket. 

E. What are the economic and 

employment impacts? 

Based on the analysis presented in the 

RIA, the proposed action is projected to 

result in certain changes to power 

system operation as a compliance 

approach with the standards. See Table 

14 of this preamble for a variety of 

important energy market impacts for 

2020, 2025, and 2030 under both the 

rate-based and mass-based federal plan 

approaches described in Section VIII.B 

of this preamble and presented in the 

RIA for this proposal. 

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 the EGs provide 

significant flexibilities and states 

implementing the EGs may choose to 

mitigate impacts to some markets 

outside the utility power sector. 

Similarly, demand for new generation or 

DS–EE as a result of states 

implementing the guidelines can result 

in shifts in production and profitability 

for firms that supply those goods and 

services. 

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, 

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innovation, competitiveness, and job 

creation. It must be based on the best 

available science.’’ (Executive Order 

13563, 2011). Although standard 

benefit-cost analyses have not typically 

included a separate analysis of 

regulation-induced employment 

impacts, we typically conduct 

employment analyses. While the 

economy continues to move toward full 

employment, employment impacts are 

of particular concern and questions may 

arise about their existence and 

magnitude. 

The EPA’s employment analysis 

includes projected employment impacts 

associated with modeled federal plan 

approaches for the electric power 

industry, coal and natural gas 

production, and DS–EE activities. These 

projections are derived, in part, from a 

detailed model of the utility power 

sector used for this regulatory analysis, 

and U.S. government data on 

employment and labor productivity. In 

the electricity, coal, and natural gas 

sectors, the EPA estimates that the 

proposed action could result in a net 

decrease of approximately 25,000 jobyears in 2025 under the rate-based 

federal plan approach and 

approximately 26,000 job-years in 2025 

under the mass-based approach. For 

2030, the estimates of the net decrease 

in job-years are 31,000 under the ratebased approach and 34,000 under the 

mass-based approach. The agency is 

also offering an illustrative calculation 

of potential employment effects due to 

DS–EE programs. Employment impacts 

from DS–EE programs in 2030 could 

range from approximately 52,000 to 

83,000 jobs under the proposal. 

By its nature, DS–EE reduces overall 

demand for electric power. The EPA 

recognizes as more efficiency is built 

into the U.S. power system over time, 

lower fuel requirements may lead to 

fewer jobs in the coal and natural gas 

extraction sectors, as well as in fossil 

fuel-fired EGU construction and 

operation than would otherwise have 

been expected. The EPA also recognizes 

the fact that, in many cases, 

employment gains and losses that might 

be attributable to this rule would be 

expected to affect different sets of 

people. Moreover, workers who lose 

jobs in these sectors may find 

employment elsewhere just as workers 

employed in new jobs in these sectors 

may have been previously employed 

elsewhere. Therefore, the employment 

estimates reported in these sectors may 

include workers previously employed 

elsewhere. This analysis also does not 

capture potential economy-wide 

impacts due to changes in prices (of 

fuel, electricity, or labor, for example) or 

other factors such as improved labor 

productivity and reduced health care 

expenditures resulting from cleaner air. 

For these reasons, the numbers reported 

here should not be interpreted as a net 

national employment impact. 

F. What are the benefits of the proposed 

action? 

Implementing the proposed action 

will generate benefits by reducing 

emissions of CO2 and criteria pollutant 

precursors, including SO2, NOX, and 

directly emitted particles. SO2 and NOX

are precursors to PM2.5 (particles smaller 

than 2.5 microns), and NOX is a 

precursor to ozone. The estimated 

benefits associated with these emission 

reductions are beyond those achieved 

by previous EPA rulemakings including 

the Mercury and Air Toxics Standards 

rule. The health and welfare benefits 

from reducing air pollution are 

considered co-benefits for this proposal. 

For this rulemaking, we were only able 

to quantify the climate benefits from 

reduced emissions of CO2 and the 

health co-benefits associated with 

reduced exposure to PM2.5 and ozone. 

There are many additional benefits 

which we are not able to quantify, 

leading to an underestimate of 

monetized benefits. In summary, we 

estimate the total combined climate 

benefits and health co-benefits for the 

rate-based federal plan approach to be 

$3.5 to $4.6 billion in 2020, $18 to $28 

billion in 2025, and $34 to $54 billion 

in 2030 (3 percent discount rate, 2011$). 

Total combined climate benefits and 

health co-benefits for the mass-based 

federal plan approach are estimated to 

be $5.3 to $8.1 billion in 2020, $19 to 

$29 billion in 2025, and $32 to $48 

billion in 2030 (3 percent discount rate, 

2011$). A summary of the emission 

reductions and monetized benefits 

estimated for this rule at all discount 

rates is provided in Tables 15 through 

17 of this preamble. 

TABLE 15—SUMMARY OF THE MONETIZED GLOBAL CLIMATE BENEFITS FOR THE PROPOSAL

[Billions of 2011$] a

Year Discount rate (statistic) 

Monetized climate benefits 

2020 2025 2030 

Rate-based Federal Plan Approach 

CO2 Reductions (million short tons) ............... ......................................................................... 69 232 415 

5 percent (average SC–CO2) ......................... $0.80 $3.1 $6.4 

3 percent (average SC–CO2) ......................... 2.8 10 20 

2.5 percent (average SC–CO2) ...................... 4.1 15 29 

3 percent (95th percentile SC–CO2) .............. 8.2 31 61 

Mass-based Federal Plan Approach 

CO2 Reductions (million short tons) ............... ......................................................................... 81 265 413 

5 percent (average SC–CO2) ......................... $0.94 $3.6 $6.4 

3 percent (average SC–CO2) ......................... 3.3 12 20 

2.5 percent (average SC–CO2) ...................... 4.9 17 29 

3 percent (95th percentile SC–CO2) .............. 9.7 35 60 

a Climate benefit estimates reflect impacts from CO2 emission changes in the analysis years presented in the table and do not account for 

changes in 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. 

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TABLE 16—SUMMARY OF THE MONETIZED HEALTH CO-BENEFITS IN THE U.S. FOR THE PROPOSAL, RATE-BASED FEDERAL

PLAN APPROACH

[Billions of 2011$] a

Pollutant 

National 

emission 

reductions 

(thousands of 

short tons) 

Monetized 

health 

co-benefits 

(3 percent 

discount) 

Monetized 

health 

co-benefits 

(7 percent 

discount) 

Rate-Based Federal Plan Approach, 2020 

PM2.5 precursors b

SO2 .............................................................................................................................................. 14 $0.44 to $0.99 $0.39 to $0.89 

NOX .............................................................................................................................................. 50 $0.14 to $0.33 $0.13 to $0.30 

Ozone precursor c

NOX (ozone season only) ............................................................................................................ 19 $0.12 to $0.52 $0.12 to $0.52 

Total Monetized Health Co-benefits $0.70 to $1.8 $0.64 to $1.7 

Total Monetized Health Co-benefits combined with Monetized Climate Benefits d $3.5 to $4.6 $3.5 to $4.5 

Rate-Based Federal Plan Approach, 2025 

PM2.5 precursors b

SO2 .............................................................................................................................................. 178 $6.4 to $14 $5.7 to $13 

NOX .............................................................................................................................................. 165 $0.56 to $1.3 $0.50 to $1.1 

Ozone precursor c

NOX (ozone season only) ............................................................................................................ 70 $0.49 to $2.1 $0.49 to $2.1 

Total Monetized Health Co-benefits $7.4 to $18 $6.7 to $16 

Total Monetized Health Co-benefits combined with Monetized Climate Benefits d $18 to $28 $17 to $26 

Rate-Based Federal Plan Approach, 2030 

PM2.5 precursors b

SO2 .............................................................................................................................................. 318 $12 to $28 $11 to $25 

NOX .............................................................................................................................................. 282 $1.0 to $2.3 $0.93 to $2.1 

Ozone precursor c

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 

aAll 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 United States. bThe monetized PM2.5 co-benefits reflect the human health benefits associated with reducing exposure to PM2.5 through reductions of PM2.5

precursors, such as SO2 and NOX. The co-benefits do not include the benefits of reductions in directly emitted PM2.5. These additional benefits 

would increase overall benefits by a few percent based on the analyses conducted for the proposed Clean Power Plan EGs. PM co-benefits are 

shown as a range reflecting the use of two concentration-response functions, with the lower end of the range based on a function from Krewski 

et al. (2009) and the upper end based on a function from Lepeule et al. (2012). These models assume that all fine particles, regardless of their 

chemical composition, are equally potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type. cThe monetized ozone co-benefits reflect the human health benefits associated with reducing exposure to ozone through reductions of NOX

during the ozone season. Ozone co-benefits are shown as a range reflecting the use of several different concentration-response functions, with 

the lower end of the range based on a function from Bell, et al. (2004) and the upper end based on a function from Levy, et al. (2005). Ozone 

co-benefits occur in the analysis year, so they are the same for all discount rates. dWe estimate climate benefits associated with four different values of a one ton CO2 reduction (model average at 2.5 percent discount rate, 3 

percent, and 5 percent; 95th percentile at 3 percent). Referred to as the social cost of carbon, each value increases over time. For the purposes 

of this table, we show the benefits associated with the model average at 3 percent discount rate, however we emphasize the importance and 

value of considering the full range of social cost of carbon values. We provide combined climate and health estimates based on additional discount rates in the RIA. 

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129 Docket ID EPA–HQ–OAR–2013–0495, 

Technical Support Document: Technical Update of 

the Social Cost of Carbon for Regulatory Impact 

Continued 

TABLE 17—SUMMARY OF THE MONETIZED HEALTH CO-BENEFITS IN THE U.S. FOR THE PROPOSAL, MASS-BASED FEDERAL

PLAN APPROACH

[Billions of 2011$] a

Pollutant 

National emission reductions 

(thousands of 

short tons) 

Monetized 

health co-benefits 

(3 percent discount) 

Monetized 

health co-benefits 

(7 percent discount) 

Mass-Based Federal Plan Approach, 2020 

PM2.5 precursors b

SO2 .............................................................................................................................................. 54 $1.7 to $3.8 $1.5 to $3.4 

NOX .............................................................................................................................................. 60 $0.17 to $0.39 $0.16 to $0.36 

Ozone precursor c

NOX (ozone season only) ............................................................................................................ 23 $0.14 to $0.61 $0.14 to $0.61 

Total Monetized Health Co-benefits $2.0 to $4.8 $1.8 to $4.4 

Total Monetized Health Co-benefits combined with Monetized Climate Benefits d $5.3 to $8.1 $5.1 to $7.7 

Mass-Based Federal Plan Approach, 2025 

PM2.5 precursors b

SO2 .............................................................................................................................................. 185 $6.0 to $13 $5.4 to $12 

NOX .............................................................................................................................................. 203 $0.58 to $1.3 $0.52 to $1.2 

Ozone precursor c

NOX (ozone season only) ............................................................................................................ 88 $0.56 to $2.4 $0.56 to $2.4 

Total Monetized Health Co-benefits $7.1 to $17 $6.5 to $16 

Total Monetized Health Co-benefits combined with Monetized Climate Benefits d $19 to $29 $18 to $27 

Mass-Based Federal Plan Approach, 2030 

PM2.5 precursors b

SO2 .............................................................................................................................................. 280 $10 to $23 $9.0 to $20 

NOX .............................................................................................................................................. 278 $0.87 to $2.0 $0.79 to $1.8 

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 

aAll 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 United States. bThe monetized PM2.5 co-benefits reflect the human health benefits associated with reducing exposure to PM2.5 through reductions of PM2.5

precursors, such as SO2 and NOX. The co-benefits do not include the benefits of reductions in directly emitted PM2.5. These additional benefits 

would increase overall benefits by a few percent based on the analyses conducted for the proposed Clean Power Plan EGs. PM co-benefits are 

shown as a range reflecting the use of two concentration-response functions, with the lower end of the range based on a function from Krewski 

et al. (2009) and the upper end based on a function from Lepeule et al. (2012). These models assume that all fine particles, regardless of their 

chemical composition, are equally potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type. cThe monetized ozone co-benefits reflect the human health benefits associated with reducing exposure to ozone through reductions of NOX

during the ozone season. Ozone co-benefits are shown as a range reflecting the use of several different concentration-response functions, with 

the lower end of the range based on a function from Bell, et al. (2004) and the upper end based on a function from Levy, et al. (2005). Ozone 

co-benefits occur in the analysis year, so they are the same for all discount rates. dWe estimate climate benefits associated with four different values of a one ton CO2 reduction (model average at 2.5 percent discount rate, 3 

percent, and 5 percent; 95th percentile at 3 percent). Referred to as the social cost of carbon, each value increases over time. For the purposes 

of this table, we show the benefits associated with the model average at 3 percent discount rate, however we emphasize the importance and 

value of considering the full range of social cost of carbon values. We provide combined climate and health estimates based on additional discount rates in the RIA. 

The EPA has used the social cost of 

carbon (SC–CO2) estimates presented in 

the Technical Support Document: 

Technical Update of the Social Cost of 

Carbon for Regulatory Impact Analysis 

Under Executive Order 12866 (May 

2013, Revised July 2015) (‘‘current 

TSD’’) to analyze CO2 climate impacts of 

this rulemaking.129 We refer to these 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

65046 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Proposed Rules 

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, DOE, 

Department of Transportation, Domestic Policy 

Council, Environmental Protection Agency, 

National Economic Council, Office of Management 

and Budget, Office of Science and Technology 

Policy, and Department of Treasury (May 2013, 

Revised July 2015). Available at: http://

www.whitehouse.gov/sites/default/files/omb/

inforeg/scc-tsd-final-july-2015.pdf. 

130 Docket ID EPA–HQ–OAR–2009–0472–114577, 

Technical Support Document: Social Cost of Carbon 

for Regulatory Impact Analysis Under Executive 

Order 12866, Interagency Working Group on Social 

Cost of Carbon, with participation by the Council 

of Economic Advisers, Council on Environmental 

Quality, Department of Agriculture, Department of 

Commerce, Department of Energy, Department of 

Transportation, Environmental Protection Agency, 

National Economic Council, Office of Energy and 

Climate Change, Office of Management and Budget, 

Office of Science and Technology Policy, and 

Department of Treasury (February 2010). Also 

available at: http://www.whitehouse.gov/sites/

default/files/omb/inforeg/for-agencies/Social-Costof-Carbon-for-RIA.pdf. 

131The current version of the TSD is available at: 

https://www.whitehouse.gov/sites/default/files/

omb/inforeg/scc-tsd-final-july-2015.pdf, Docket ID 

EPA–HQ–OAR–2013–0495, Technical Support 

Document: Technical Update of the Social Cost of 

Carbon for Regulatory Impact Analysis Under 

Executive Order 12866, Interagency Working Group 

on Social Cost of Carbon, with participation by 

Council of Economic Advisers, Council on 

Environmental Quality, Department of Agriculture, 

Department of Commerce, Department of Energy, 

Department of Transportation, Domestic Policy 

Council, Environmental Protection Agency, 

National Economic Council, Office of Management 

and Budget, Office of Science and Technology 

Policy, and Department of Treasury (May 2013, 

Revised July 2015). 

132See https://www.whitehouse.gov/omb/oira/

social-cost-of-carbon for additional details, 

including the OMB Response to Comments and the 

SC–CO2 TSDs. 

133The current version of the TSD is available at: 

https://www.whitehouse.gov/sites/default/files/

omb/inforeg/scc-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 Gross Domestic Product and Related 

Price Measures: Indexes and Percent Changes, 

http://www.gpo.gov/fdsys/pkg/ECONI-2013-02/pdf/

ECONI-2013-02-Pg3.pdf. 

estimates, which were developed by the 

U.S. government, as ‘‘SC–CO2

estimates.’’ The SC–CO2 is a metric that 

estimates the monetary value of impacts 

associated with marginal changes in 

CO2 emissions in a given year. It 

includes a wide range of anticipated 

climate impacts, such as net changes in 

agricultural productivity and human 

health, property damage from increased 

flood risk, and changes in energy system 

costs, such as reduced costs for heating 

and increased costs for air conditioning. 

It is typically used to assess the avoided 

damages as a result of regulatory actions 

(i.e., benefits of rulemakings that lead to 

an incremental reduction in cumulative 

global CO2 emissions). 

The SC–CO2 estimates used in this 

analysis were developed over many 

years, using the best science available, 

and with input from the public. 

Specifically, an interagency working 

group (IWG) that included the EPA and 

other executive branch agencies and 

offices used three integrated assessment 

models (IAMs) to develop the SC–CO2

estimates and recommended four global 

values for use in regulatory analyses. 

The SC–CO2 estimates were first 

released in February 2010 and updated 

in 2013 using new versions of each 

IAM. The 2010 SC–CO2 Technical 

Support Document (2010 TSD) 130

provides a complete discussion of the 

methods used to develop these 

estimates and the current TSD presents 

and discusses the 2013 update 

(including two recent minor corrections 

to the estimates).131

OMB’s Office of Information and 

Regulatory Affairs received comments 

in response to a request for public 

comment on the approach used to 

develop the estimates. After careful 

evaluation of the full range of comments 

submitted to OMB, the IWG continues 

to recommend the use of the SC–CO2

estimates in RIA.132 With the release of 

the response to comments, the IWG 

announced plans to obtain expert 

independent advice from the National 

Academies of Sciences, Engineering, 

and Medicine (Academies) to ensure 

that the SC–CO2 estimates continue to 

reflect the best available scientific and 

economic information on climate 

change. The Academies review will be 

informed by the public comments 

received and focus on the technical 

merits and challenges of potential 

approaches to improving the SC–CO2

estimates in future updates. See the EPA 

Response to Comments document for 

the complete response to comments 

received on SC–CO2 as part of this 

rulemaking. 

Concurrent with OMB’s publication of 

the response to comments on SC–CO2

and announcement of the Academies 

process, OMB posted a revised TSD that 

includes two minor technical 

corrections to the current estimates. One 

technical correction addressed an 

inadvertent omission of climate change 

damages in the last year of analysis 

(2300) in one model and the second 

addressed a minor indexing error in 

another model. On average the revised 

SC–CO2 estimates are one dollar less 

than the mean SC–CO2 estimates 

reported in the November 2013 revision 

to the May 2013 TSD. The change in the 

estimates associated with the 95th 

percentile estimates when using a 3 

percent discount rate is slightly larger, 

as those estimates are heavily 

influenced by the results from the 

model that was affected by the indexing 

error. 

The EPA, as a member of the IWG on 

the SC–CO2, has carefully examined and 

evaluated the minor technical 

corrections in the revised TSD and the 

public comments submitted to OMB’s 

SC–CO2 comment process. The EPA 

concurs with the IWG’s conclusion that 

it is reasonable, and scientifically 

appropriate, to use the current SC–CO2

estimates for purposes of RIA, including 

for this proceeding. 

The four SC–CO2 estimates are as 

follows: $12, $40, $60, and $120 per 

short ton of CO2 emissions in the year 

2020 (2011$).133 The first three values 

are based on the average SC–CO2 from 

the three IAMs, at discount rates of 5, 

3, and 2.5 percent, respectively. The 

SC–CO2 value at several discount rates 

are included because the literature 

shows that the SC–CO2 is quite sensitive 

to assumptions about the discount rate, 

and because no consensus exists on the 

appropriate rate to use in an 

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 higherthan-expected impacts from temperature 

change further out in the tails of the SC– 

CO2 distribution (representing less 

likely, but potentially catastrophic, 

outcomes). 

There are limitations in the estimates 

of the benefits from this proposal, 

including the omission of climate and 

other CO2 related benefits that could not 

be monetized. The 2010 TSD discusses 

a number of limitations to the SC–CO2

analysis, including the incomplete way 

in which the IAMs capture catastrophic 

and non-catastrophic impacts, their 

incomplete treatment of adaptation and 

technological change, uncertainty in the 

extrapolation of damages to high 

temperatures, and assumptions 

regarding risk aversion. Currently, IAMs 

do not assign value to all of the 

important impacts of CO2 recognized in 

the literature, such as ocean 

acidification or potential tipping points, 

for various reasons, including the 

inherent difficulties in valuing nonmarket 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 

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134http://www.epa.gov/airquality/benmap/

index.html. 

135U.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 2012). Available at: http://

www.epa.gov/ttnecas1/regdata/RIAs/finalria.pdf. 

136U.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 2008). Available at: http://

www.epa.gov/ttnecas1/regdata/RIAs/452_R_08_

003.pdf. 

137U.S. Environmental Protection Agency (U.S. 

EPA). 2010. Section 3: Re-analysis of the Benefits 

of Attaining Alternative Ozone Standards to 

Incorporate Current Methods. Available at: http://

www.epa.gov/ttnecas1/regdata/RIAs/s3- 

supplemental_analysis-updated_benefits11- 

5.09.pdf. 

138U.S. Environmental Protection Agency. 2013. 

Technical support document: Estimating the Benefit 

per Ton of Reducing PM2.5 Precursors from 17 

Sectors. Research Triangle Park, NC: Office of Air 

and Radiation, Office of Air Quality Planning and 

Standards, January. Available at: http://

www.epa.gov/airquality/benmap/models/Source_

Apportionment_BPT_TSD_1_31_13.pdf. 

139 Krewski D.; M. Jerrett; R. T. Burnett; R. Ma; 

E. Hughes; Y. Shi, et al. 2009. Extended Follow-up 

and Spatial Analysis of the American Cancer 

Society Study Linking Particulate Air Pollution and 

Mortality. Health Effects Institute. (HEI Research 

Report number 140). Boston, MA: Health Effects 

Institute. 

140Lepeule, 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. 

141Roman, 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. 

142Bell, 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. 

143Levy, 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. 

144U.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 2009). Available at: http://

cfpub.epa.gov/si/si_public_record_Report.cfm?

dirEntryId=216546. 

independent expert advice on technical 

opportunities to improve the SC–CO2

estimates from the Academies. The 

Academies’ process will help to ensure 

that the SC–CO2 estimates used by the 

federal government continue to reflect 

the best available science and 

methodologies. Additional details are 

provided in the TSDs. 

The health co-benefits estimates 

represent the total monetized human 

health benefits for populations exposed 

to reduced PM2.5 and ozone resulting 

from emission reductions from the 

federal plan approaches examined in 

the RIA for this proposal. Unlike the 

global SC–CO2 estimates, the air 

pollution health co-benefits are 

estimated for the contiguous United 

States only. We used a ‘‘benefit-per-ton’’ 

approach to estimate the benefits of this 

rulemaking. To create the PM2.5 benefitper-ton estimates, we conducted air 

quality modeling for an illustrative 

scenario reflecting the proposed Clean 

Power Plan EGs to convert precursor 

emissions into changes in ambient PM2.5

and ozone concentrations. We then used 

these air quality modeling results in 

BenMAP 134 to calculate average 

regional benefit-per-ton estimates using 

the health impact assumptions used in 

the PM NAAQS RIA 135 and Ozone 

NAAQS RIAs.136 137 The three regions 

were the Eastern United States, Western 

United States, and California. To 

calculate the co-benefits for this 

proposal, we multiplied the regional 

benefit-per-ton estimates generated from 

modeling of the proposed Clean Power 

Plan EGs standards by the 

corresponding regional emission 

reductions for this proposal.138 All 

benefit-per-ton estimates reflect the 

geographic distribution of the modeled 

emissions for the proposed Clean Power 

Plan EGs, which may not exactly match 

the emission reductions in this 

proposed rulemaking, and thus they 

may not reflect the local variability in 

population density, meteorology, 

exposure, baseline health incidence 

rates, or other local factors for any 

specific location. More information 

regarding the derivation of the benefitper-ton estimates is available in the 

Clean Power Plan Final Rule RIA. 

PM benefit-per-ton values are 

generated using two concentrationresponse functions, Krewski et al. 

(2009) 139 and Lepeule et al. (2012).140

These models assume that all fine 

particles, regardless of their chemical 

composition, are equally potent in 

causing premature mortality because the 

scientific evidence is not yet sufficient 

to allow differentiation of effect 

estimates by particle type. Even though 

we assume that all fine particles have 

equivalent health effects, the benefitper-ton estimates vary between PM2.5

precursors depending on the location 

and magnitude of their impact on PM2.5

concentrations, which drive population 

exposure. 

It is important to note that the 

magnitude of the PM2.5 and ozone cobenefits is largely driven by the 

concentration response functions for 

premature mortality and the value of a 

statistical life used to value reductions 

in premature mortality. For PM2.5, we 

use two key empirical studies, one 

based on the American Cancer Society 

cohort study (Krewski et al., 2009) and 

one based on the extended Six Cities 

cohort study (Lepuele et al., 2012). The 

PM2.5 co-benefits results are presented 

as a range based on benefit-per-ton 

estimates calculated using the 

concentration-response functions from 

these two epidemiology studies, but this 

range does not capture the full range of 

uncertainty inherent in the co-benefits 

estimates. In the RIA for this rule, which 

is available in the docket, we also 

include PM2.5 co-benefits estimates 

using benefit-per-ton estimates based on 

expert judgments of the effect of PM2.5

on premature mortality (Roman et al., 

2008) 141 as a characterization of 

uncertainty regarding the PM2.5- 

mortality relationship. 

For the ozone co-benefits, we present 

the results as a range reflecting benefitper-ton estimates which use several 

different concentration-response 

functions for mortality, with the lower 

end of the range based on a benefit-perton estimate using the function from 

Bell et al. (2004) 142 and the upper end 

based on a benefit-per-ton estimate 

using the function from Levy et al. 

(2005).143 Similar to PM2.5, the range of 

ozone co-benefits does not capture the 

full range of inherent uncertainty. 

In this analysis, in estimating the 

benefits-per-ton for PM2.5 precursors, 

the EPA assumes that the health impact 

function for fine particles is without a 

threshold. This is based on the 

conclusions of the EPA’s Integrated 

Science Assessment for Particulate 

Matter,144 which evaluated the 

substantial body of published scientific 

literature, reflecting thousands of 

epidemiology, toxicology, and clinical 

studies, that documents the association 

between elevated PM2.5 concentrations 

and adverse health effects, including 

increased premature mortality. This 

assessment, which was twice reviewed 

by the EPA’s independent Science 

Advisory Board, concluded that the 

scientific literature consistently finds 

that a no-threshold model most 

adequately portrays the PM-mortality 

concentration-response relationship. 

In general, we are more confident in 

the magnitude of the risks we estimate 

from simulated PM2.5 concentrations 

that coincide with the bulk of the 

observed PM concentrations in the 

epidemiological studies that are used to 

estimate the benefits. Likewise, we are 

less confident in the risk we estimate 

from simulated PM2.5 concentrations 

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65048 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Proposed Rules 

145 In addition, site-specific emission reductions 

will depend upon how states implement the 

guidelines. 

146Six Common Air Pollutants. http://

www.epa.gov/oaqps001/urbanair/. 

that fall below the bulk of the observed 

data in these studies. 

For this analysis, policy-specific air 

quality data are not available,145 and 

thus, we are unable to estimate the 

percentage of premature mortality 

associated with this specific rule that is 

above the lowest measured PM2.5 levels 

(LML) for the two PM2.5 mortality 

epidemiology studies that form the basis 

for our analysis. As a surrogate measure 

of mortality impacts above the LML, we 

provide the percentage of the 

population exposed above the 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 (mg/m3). 

Using the Lepeule et al. (2012) study, 46 

percent of the population is exposed 

above the LML of 8 mg/m3. It is 

important to note that baseline exposure 

is only one parameter in the health 

impact function, along with baseline 

incidence rates, population, and change 

in air quality. 

Every benefit analysis examining the 

potential effects of a change in 

environmental protection requirements 

is limited, to some extent, by data gaps, 

model capabilities (such as geographic 

coverage), and uncertainties in the 

underlying scientific and economic 

studies used to configure the benefit and 

cost models. Despite these uncertainties, 

we believe the air quality co-benefit 

analysis for this rule provides a 

reasonable indication of the expected 

health benefits of the air pollution 

emission reductions for the illustrative 

analysis of this proposed action under a 

set of reasonable assumptions. This 

analysis does not include the type of 

detailed uncertainty assessment found 

in the 2012 PM2.5 NAAQS RIA (U.S. 

EPA, 2012) because we lack the 

necessary air quality input and 

monitoring data to conduct a complete 

benefits assessment. In addition, using a 

benefit-per-ton approach adds another 

important source of uncertainty to the 

benefits estimates. The 2012 PM2.5

NAAQS benefits analysis provides an 

indication of the sensitivity of our 

results to various assumptions. 

We note that the monetized cobenefits estimates shown here do not 

include several important benefit 

categories, including exposure to SO2, 

NOX, and HAP (e.g., mercury and 

hydrogen chloride), as well as 

ecosystem effects and visibility 

impairment. Although we do not have 

sufficient information or modeling 

available to provide monetized 

estimates for this rule, a qualitative 

assessment of these unquantified 

benefits is included in the RIA for this 

proposal. In addition, in the RIA for this 

proposal, we did not estimate changes 

in emissions of directly emitted 

particles. As a result, quantified PM2.5

related benefits are underestimated by a 

relatively small amount. In the RIA for 

the proposed Clean Power Plan EGs, the 

benefits from reductions in directly 

emitted PM2.5 were less than 10 percent 

of total monetized health co-benefits 

across all scenarios and years. 

For more information on the benefits 

analysis, please refer to the RIA for this 

rule, which is available in the 

rulemaking docket. 

IX. Community and Environmental 

Justice Considerations 

In this section we provide an 

overview of the actions that the agency 

is taking to help ensure that vulnerable 

communities are not disproportionately 

impacted by this rulemaking. 

As described in the Executive 

Summary, climate change is an EJ issue. 

Low-income communities and 

communities of color already 

overburdened with pollution are likely 

to be disproportionately affected by, and 

less resilient to, the impacts of climate 

change. This rulemaking will provide 

broad benefit to communities across the 

nation, as its purpose is to reduce GHGs, 

the most significant driver of climate 

change. While addressing climate 

change will provide broad benefits, it is 

particularly beneficial to low-income 

populations and some communities of 

color (in particular, populations defined 

jointly by ethnic/racial characteristics 

and geographic location) where people 

are most vulnerable to the impacts of 

climate change (a more robust 

discussion of the impacts of climate 

change on vulnerable communities is 

provided in the Executive Order 12898 

discussion in section X.J of this 

preamble). While climate change is a 

global phenomenon, the adverse effects 

of climate change can be very localized, 

as impacts such as storms, flooding, and 

droughts are experienced in individual 

communities. 

Vulnerable communities also often 

receive more than their fair share of 

conventional air pollution, with the 

attendant adverse health impacts. 

The changes in electricity generation 

that will result from this rule will 

further benefit communities by reducing 

existing air pollution that directly 

contributes to adverse localized health 

effects. These air quality improvements 

will be achieved through this rule 

because the EGUs that emit the most 

GHGs also have the highest emissions of 

conventional pollutants, such as SO2, 

NOX, fine particles, and HAP. These 

pollutants are known to contribute to 

adverse health outcomes, including the 

development of heart and 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.146

The EPA expects that the reductions in 

utilization of higher-emitting units 

likely to occur during the 

implementation of federal plans will 

produce significant reductions in 

emissions of conventional pollutants, 

particularly in those communities 

already overburdened by pollution, 

which are often low-income 

communities, communities of color, and 

indigenous communities. These 

reductions will have beneficial effects 

on air quality and public health, both 

locally and regionally. Further, this 

rulemaking complements other actions 

already taken by the EPA to reduce 

conventional pollutant emissions and 

improve health outcomes for 

overburdened communities. 

By reducing millions of tons of CO2

emissions that are contributing to global 

GHG levels and providing strong 

leadership to encourage meaningful 

reductions by countries across the globe, 

this rule is a significant step to address 

health and economic impacts of climate 

change that will fall disproportionately 

on vulnerable communities. By 

reducing millions of tons of 

conventional air pollutants, this 

proposed rule will lead to better air 

quality and improved health in those 

communities. In the comment period for 

the Clean Power Plan, 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 on the EGs. 

While the agency expects overall 

emission decreases as a result of this 

rulemaking, we recognize that some 

EGUs may operate more frequently. To 

the extent that we project increases in 

utilization as a result of this rulemaking, 

we expect these increases to occur 

generally in lower-emitting NGCC units, 

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147The proximity analysis was conducted using 

the EPA’s environmental justice mapping and 

screening tool, EJSCREEN. 

which have minimal or no emissions of 

SO2 and HAP, lower emissions of 

particulate matter, and much lower 

emissions of NOX compared to higheremitting steam units. We acknowledge 

the concerns that have been raised on 

this point, but also the difficulty in 

anticipating prior to plan 

implementation where those impacts 

might occur. As described below, the 

EPA intends to conduct an assessment 

of whether and where emission 

increases may result from plan 

implementation and mitigate adverse 

impacts, if any, in overburdened 

communities. 

In addition to the many positive 

anticipated health benefits of this 

rulemaking, it also will increase the use 

of clean energy and will encourage EE. 

These changes in the electricity 

generation system, which are already 

occurring, but may be accelerated by 

this program, are expected to have other 

positive benefits for communities. The 

electricity sector is, and will continue to 

be, investing more in RE and EE. The 

construction of renewable generation 

and the implementation of EE programs 

such as residential weatherization will 

bring investment and employment 

opportunities to the communities where 

they take place. It is important to ensure 

that all communities share in these 

benefits. And while we estimate that the 

benefits of this program will greatly 

exceed its costs (as noted in the RIA for 

this rulemaking), it is also important to 

ensure that to the extent there are 

increases in electricity costs, that those 

do not fall disproportionately on those 

least able to afford them. 

The EPA has engaged with 

community groups throughout this 

rulemaking and we received many 

comments on the issues outlined above 

from community groups, EJ 

organizations, faith-based organizations, 

public health organizations, and others. 

This input has informed this proposed 

rulemaking and prompted the EPA to 

consider other steps that the agency can 

take in the short and long term to 

consider EJ and impacts to communities 

in federal plan development and 

implementation. 

It has also prompted us to work with 

our federal partners to make sure that 

communities have information on 

federal resources available to assist 

them. We describe these resources 

below, as well as resources that the EPA 

will be providing to assist communities 

in accessing EE/RE and financial 

assistance programs. 

Finally, and importantly, we 

recognize that communities must be 

able to participate meaningfully in the 

development of this rulemaking. In this 

section, we discuss the steps that the 

EPA will take to assist communities in 

engaging with the agency throughout 

the comment period of this rulemaking. 

A. Proximity Analysis 

The EPA is committed to ensuring 

that there is no disproportionate, 

adverse impact on overburdened 

communities as a result of this proposed 

rulemaking. To provide information 

fundamental to beginning that process, 

the EPA has conducted a proximity 

analysis for this proposed rulemaking 

that summarizes demographic data on 

the communities located near power 

plants.147 The EPA understands that, in 

order to prevent disproportionately high 

and adverse human health or 

environmental effects on these 

communities, both the agency and 

communities must have information on 

the communities living near facilities, 

including demographic data, and that 

accessing and using census data files 

requires expertise that some community 

groups may lack. Therefore, the EPA 

used census data from the American 

Community Survey (ACS) 2008–2012 to 

conduct a proximity analysis that can 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 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 low-income 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 (EJ) 

considerations, we use the terms 

‘‘vulnerable’’ or ‘‘overburdened’’ when 

referring to these communities. Our 

intent is for these terms to be 

understood in an expansive sense, in 

order to capture the full scope of 

communities, including indigenous 

communities most often located in rural 

areas, that are central to our EJ and 

community considerations. 

As stated in the Executive Order 

12898 discussion located in section X.J 

of this preamble, the EPA believes that 

all communities will benefit from this 

proposed rulemaking because this 

action directly addresses the impacts of 

climate change by limiting GHG 

emissions through the establishment of 

CO2 emission standards for existing 

affected fossil fuel-fired power plants. 

The EPA also believes that the 

information provided in the proximity 

analysis will promote engagement 

between vulnerable communities and 

the agency throughout the rulemaking 

process. In addition to providing the 

proximity analysis in the docket of this 

rulemaking, the EPA will make it 

publicly available on its Clean Power 

Plan Communities Portal that will be 

linked to this rulemaking’s Web site 

(http://www.epa.gov/cleanpowerplan). 

Furthermore, the EPA has also created 

an interactive mapping tool that 

illustrates where power plants are 

located and provides information on a 

state level. This tool is available at: 

http://cleanpowerplanmaps.epa.gov/

CleanPowerPlan/. 

B. Community Engagement in This 

Rulemaking Process 

The EPA has heard from vulnerable 

communities throughout the outreach 

process for the Clean Power Plan that it 

is imperative for communities to have 

an understanding of how rulemakings 

that target climate change work. They 

expressed a desire to know how these 

programs may benefit their communities 

and what the potential adverse impacts 

of the rules may be on their 

communities. We intend to provide 

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148http://www.eda.gov/power/. 

communities with the information that 

they need to engage with the agency 

throughout the comment period. 

We have received feedback from 

communities that public hearings, 

webinars, and in-person meetings are 

the most effective ways to engage with 

them and to provide them with the 

information they need to understand the 

rulemaking process. Therefore, for this 

rulemaking, in addition to conducting 

public hearings for all members of the 

American public, the agency will hold 

a national webinar for communities in 

the early stages of the comment period. 

The goal of this webinar will be to walk 

communities through the highlights of 

the preamble, so they have an 

understanding of how the rulemaking 

may potentially affect their 

communities and they will have the 

contextual information they need to 

actively engage with the agency 

throughout the comment period. 

Additionally, because we received 

positive feedback on the effectiveness of 

the face-to-face meetings conducted on 

the regional level, each region will be 

offering an outreach meeting(s) for 

communities. The goal of these 

meetings is to build a level of 

understanding on this rulemaking to 

enable vulnerable communities to 

actively engage with the agency 

throughout the comment period. 

Furthermore, we will follow up on 

common issues raised during the 

outreach meetings with national 

conference calls, specifically targeted 

for vulnerable communities. 

C. Providing Communities With Access 

to Additional Resources 

In section V.D of this preamble, we 

outline that we are seeking comment on 

whether a portion of this set-aside 

should be targeted to RE projects that 

benefit low-income communities. 

Furthermore, the EPA is seeking 

comment on how a low-income 

community should be defined as 

eligible under this set-aside. We also 

seek comment on how much of the setaside 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 lowincome communities should differ, and 

if so, in what manner, from the methods 

that are proposed to apply to other RE 

projects. 

As discussed below, there are also 

many federal programs that can help 

low-income populations access the 

benefits of RE and EE, and the economic 

benefits of a cleaner energy economy. 

In the coming months, the EPA will 

continue to provide information and 

resources for low-income communities 

on existing federal, state, local, and 

other financial assistance programs to 

encourage EE/RE opportunities that are 

already available to communities. For 

example, the EPA will provide a catalog 

of current or recent state and local 

programs that have successfully helped 

communities adopt EE/RE measures. 

The goal of these resources is to help 

vulnerable communities gain the 

benefits of this rulemaking. The use of 

these RE/EE tools can also help lowincome households reduce their 

electricity consumption and bills. 

Additionally, as part of the resources 

that we will be providing low-income 

communities, the EPA will provide 

information on the Administration’s 

Partnerships for Opportunity and 

Workforce and Economic Revitalization 

(POWER) Initative and other programs 

that specifically target economic 

development assistance to communities 

affected by changes in the coal industry 

and the utility power sector.148

D. Federal Programs and Resources 

Available to Communities 

Federal agencies have a history of 

bringing EE and RE to low-income 

communities. Earlier this summer, the 

Administration announced a new 

initiative to scale up access to solar 

energy and cut energy bills for all 

Americans, in particular low- and 

moderate-income communities, and to 

create a more inclusive solar workforce. 

As part of this new initiative, the U.S. 

DOE, the U.S. Department of Housing 

and Urban Development, U.S. 

Department of Agriculture, and the EPA 

launched a National Community Solar 

Partnership to unlock access to solar 

energy for the nearly 50 percent of 

households and businesses that are 

renters or do not have adequate roof 

space to install solar systems, with a 

focus on low- and moderate-income 

communities. The Administration also 

set a goal to install 300 MW of RE in 

federally subsidized housing by 2020 

and plants to provide technical 

assistance to make it easier to install 

solar energy on affordable housing, 

including clarifying how to use federal 

funding for EE and RE. To continue 

enhancing employment opportunities in 

the solar industry for all Americans, 

AmeriCorps is providing funding to 

deploy solar energy and create jobs in 

underserved communities, and DOE is 

working to expand solar energy 

education and opportunities for job 

training. 

These recent announcements build on 

the many existing federal programs and 

resources available to improve EE and 

accelerate the deployment of RE in 

vulnerable communities. Some 

examples of these resources include: 

The DOE’s Weatherization Assistance 

Program, Health and Human Service’s 

Low-Income Home Energy Assistance 

Program, the Department of 

Agriculture’s Energy Efficiency and 

Conservation Loan Program, High Cost 

Energy Grant Program, and the Rural 

Housing Service’s Multi-Family 

Housing Program. 

The U.S. Department of Housing and 

Urban Development supports EE 

improvements and the deployment of 

RE on affordable housing through its 

Energy Efficient Mortgage Program, 

Multifamily Property Assessed Clean 

Energy Pilot with the State of California, 

PowerSaver Program, and the use of 

Section 108 Community Development 

Block Grants. The Department of 

Treasury provides several tax credits to 

support RE development and EE in lowincome communities, including the 

New Markets Tax Credit Program and 

the Low-Income Housing Tax Credit. 

The EPA’s RE-Powering America’s Land 

Initiative promotes the reuse of 

potentially contaminated lands, 

landfills and mine sites—many of which 

are in low-income communities—for RE 

through a combination of tailored 

redevelopment tools for communities 

and developers, as well as site-specific 

technical support. The EPA’s Green 

Power Partnership is increasing 

community use of renewable electricity 

across the country and in low-income 

communities. The EPA partners with EE 

programs throughout the country that 

leverage ENERGY STAR to deliver 

broad consumer energy-saving benefits, 

of particular value to low-income 

households who can least afford high 

energy bills. ENERGY STAR also works 

with houses of worship to reduce energy 

costs—savings that can then be 

repurposed to their community mission, 

including programs and assistance to 

residents in low-income communities. 

The EPA will be working with these 

federal partners and others to ensure 

that states and vulnerable communities 

have access to information on these 

programs and their resources. 

The federal government also has a 

number of programs to expand 

employment opportunities in the energy 

sector, including for underserved 

populations. Examples of these include 

the U.S. Department of Housing and 

Urban Development, DOE, and the 

Department of Education’s ‘‘STEM, 

Energy, and Economic Development’’ 

program; DOE’s Diversity in Science 

and Technology Advances National 

Clean Energy in Solar (DISTANCEmstockstill on DSK4VPTVN1PROD with PROPOSALS2

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149 76 FR 48348, August 11, 2011. 

150See 76 FR 48347, August 11, 2011. 

151 65 FR 79831, December 20, 2000. 

152 ‘‘Cost and Performance Baseline for Fossil 

Energy Plants Volume 1: Bituminous Coal and 

Natural Gas to Electricity’’ Rev 2a, September 2013 

Revision 2, November 2010 DOE/NETL–2010/1397. 

153 Guidance on Considering Environmental 

Justice During the Development of Regulatory 

Actions. http://www.epa.gov/environmentaljustice/

resources/policy/considering-ej-in-rulemakingguide-final.pdf. May 2015. 

Solar) Program; Grid Engineering for 

Accelerated Renewable Energy 

Deployment (GEARED); the DOL’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. Assessing Impacts of Federal Plan 

Implementation 

It is important to the EPA that the 

implementation of federal plans be 

assessed in order to identify whether 

they cause any adverse impacts on 

communities already overburdened by 

disproportionate environmental harms 

and risks. The EPA will conduct its own 

assessment during the implementation 

phase of this rulemaking to determine 

whether the implementation of federal 

plans and other air quality rules are, in 

fact, reducing emissions and improving 

air quality in all areas and, or whether 

there are localized air quality impacts 

that need to be addressed under the 

Clean other CAA authorities. 

The EPA will provide trainings for 

communities on resources that they can 

use to assess localized impacts, 

especially effects of co-pollutants, of 

plans on their communities. This 

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. 

F. Co-Pollutants 

Air quality in a given area is affected 

by emissions from nearby sources and 

may be influenced by emissions that 

travel hundreds of miles and mix with 

emissions from other sources.149 In the 

CSAPR the EPA used its authority to 

reduce emissions that significantly 

contribute to downwind exposures. The 

RIA for the final CSAPR anticipates 

substantial health benefits for the 

population across a wide region. 

Similarly, the EPA believes that, like the 

CSAPR, this rulemaking will result in 

significant health benefits because it 

will reduce co-pollutant emissions of 

SO2 and NOX on a regional and national 

basis.150 Thus, localized increases in 

NOX emissions may well be more than 

offset by NOX decreases elsewhere in 

the region that produce a net 

improvement in ozone and particulate 

concentrations across the area. 

Another effect of the final CO2

emission standards for affected existing 

fossil fuel-fired EGUs may be increased 

utilization of other, unmodified EGUs— 

in particular, high efficiency gas-fired 

EGUs—with relatively low GHG 

emissions per unit of electrical output. 

These plants may operate more hours 

during the year and could emit 

pollutants, including pollutants whose 

environmental effects would be 

localized and regional rather than global 

as is the case with GHG emissions. 

Changes in utilization already occur in 

response to energy demands and 

evolving energy sources, but the final 

CO2 emission standards for affected 

existing fossil fuel-fired EGUs can be 

expected to cause more such changes. 

Increased utilization of solid fossil fuelfired units generally would not increase 

peak concentrations of PM2.5, NOX, or 

ozone around such EGUs to levels 

higher than those that are already 

occurring because peak hourly or daily 

emissions generally would not change; 

however, increased utilization may 

make periods of relatively high 

concentrations more frequent. It should 

be noted that the 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 SIPs, and 

conditions in title V operating permits, 

in addition to the guidelines in the final 

EGs rulemaking published elsewhere in 

this Federal Register. Therefore, local 

(or regional) air quality for these 

pollutants is not likely to be 

significantly affected. For natural gasfired EGUs, the EPA found that 

regulation of HAP emissions ‘‘is not 

appropriate or necessary because the 

impacts due to HAP emissions from 

such units are negligible based on the 

results of the study documented in the 

utility RTC.’’ 151 Because gas-fired EGUs 

emit essentially no mercury, increased 

utilization will not increase methyl 

mercury concentrations in water bodies 

near these affected EGUs. In studies 

done by DOE/NETL comparing cost and 

performance of coal- and NGCC-fired 

generation, they assumed SO2, NOX, PM 

(and Hg) emissions to be ‘‘negligible.’’ 

Their studies predict NOX emissions 

from a NGCC unit to be approximately 

10 times lower than a subcritical or 

supercritical coal-fired boiler.152 Many, 

although not all, NGCC units are also 

very well controlled for emissions of 

NOX through the application of after 

combustion controls such as selective 

catalytic reduction. 

G. The EPA’s Continued Engagement 

The EPA is committed to helping 

ensure that this action will not have 

disproportionate adverse human health 

or environmental effects on vulnerable 

communities. Throughout the 

implementation phase of this 

rulemaking, the agency will continue to 

provide trainings and resources to assist 

communities and as they engage with 

the agency. The EPA, through its 

outreach efforts during the comment 

period, will continue to solicit feedback 

from communities on what they would 

like additional trainings and resources 

on. 

As described above, the EPA will 

assess the impacts of this rulemaking 

during its implementation. The EPA 

will house this assessment, along with 

the proximity analysis and other 

information generated throughout the 

implementation process, on its Clean 

Power Plan Communities Portal that 

will be linked to this rulemaking’s Web 

site (http://www.epa.gov/

cleanpowerplan). In addition, the EPA 

has expanded its set of resources that 

are being developed to help 

communities understand the breadth of 

policy options and programs that have 

successfully brought EE/RE to lowincome communities. The EPA is 

committed to continuing its engagement 

with communities from the comment 

period of this rulemaking through 

federal plan implementation. 

The EPA consulted its May 2015, 

Guidance on Considering 

Environmental Justice During the 

Development of Regulatory Actions, 

when crafting this rulemaking.153 A 

more detailed discussion concerning the 

application of Executive Order 12898 in 

this rulemaking can be found in section 

X.J of this preamble. A summary of the 

EPA’s interactions with communities is 

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in the EJ Screening Report for the Clean 

Power Plan, available in the docket of 

this rulemaking. Furthermore, the EPA’s 

responses to public comments, 

including comments received from 

communities, are provided in the 

response to comments documents 

located in the docket for this 

rulemaking. 

In summary, the EPA in this proposed 

rulemaking has designed an integrative 

approach that helps to ensure that 

vulnerable communities are not 

disproportionately impacted by this 

rule. The proximity analysis that the 

agency has conducted is a central 

component of this approach. Not only is 

the proximity analysis a useful tool to 

help identify communities that may be 

impacted by this rulemaking; it will also 

help communities as they engage with 

the EPA throughout the comment 

period. It will help the EPA as we help 

low-income communities access EE/RE 

and financial assistance programs. 

Finally, in order to continue to ensure 

that overburdened communities are not 

disproportionately impacted by this 

rule, the EPA will be conducting an 

assessment during the implementation 

phase of the effects of this and other 

rules on air quality. 

X. Statutory and Executive Order 

Reviews 

Additional information about these 

statutes and Executive Orders can be 

found at http://www2.epa.gov/lawsregulations/laws-and-executive-orders. 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

This proposed action is an 

economically significant regulatory 

action that was submitted to the OMB 

for review. Any changes made in 

response to OMB recommendations 

have been documented in the docket for 

this rulemaking. The EPA prepared an 

analysis of the potential costs and 

benefits associated with this action. 

This analysis, which is contained in the 

‘‘Regulatory Impact Analysis for the 

Proposed Federal Plan Requirements for 

Greenhouse Gas Emissions from Electric 

Utility Generating Units Constructed on 

or Before January 8, 2014; Model 

Trading Rules; Amendments to 

Framework Regulations’’ (EPA–452/R– 

15–006, July 2015), is available in the 

docket and is briefly summarized in 

section VIII of this preamble. 

Consistent with Executive Order 

12866 and Executive Order 13563, the 

EPA estimated the costs and benefits for 

two alternative federal plan approaches 

to implementing the proposed federal 

plan and model trading rules. The 

proposed action will achieve the same 

levels of emissions performance as 

required of state plans under the CAA 

section 111(d) EGs for the control of 

CO2. Actions taken to comply with the 

guidelines will also reduce the 

emissions of directly-emitted PM2.5, 

SO2, and NOX. The benefits associated 

with these PM2.5, SO2, and NOX

reductions are referred to as co-benefits, 

as these reductions are not the primary 

objective of this rule. 

The RIA for this proposal analyzed 

two implementation scenarios, which 

we term the ‘‘rate-based federal plan 

approach’’ and the ‘‘mass-based federal 

plan approach.’’ It is very important to 

note that the differences between the 

analytical results for the rate-based and 

mass-based federal plan approaches 

presented in the RIA may not be 

indicative of likely differences between 

the approaches. In other words, if one 

approach performs differently than the 

other on a given metric during a given 

time period, this does not imply this 

will apply in all instances. 

It is important to note that the 

potential regulatory impacts presented 

in the Clean Power Plan Final Rule RIA 

and the RIA for this proposed rule are 

not additive. Both RIAs present 

estimates of the benefits and costs of 

achieving the emission performance 

rates of the Clean Power Plan EGs. In 

the case of the Clean Power Plan Final 

Rule RIA, the illustrative analysis 

assumes the performance rates are met 

under state plans. In the case of this RIA 

for the proposed federal plan and model 

trading rules, the same performance 

rates are accomplished but are assumed 

to be achieved under the federal plan or 

model trading rules. 

The EPA has used the social cost of 

carbon estimates presented in the 

Technical Support Document: 

Technical Update of the Social Cost of 

Carbon for Regulatory Impact Analysis 

Under Executive Order 12866 (May 

2013, Revised July 2015) (‘‘current 

TSD’’) to analyze CO2 climate impacts of 

this rulemaking. We refer to these 

estimates, which were developed by the 

U.S. government, as ‘‘SC–CO2

estimates.’’ The SC–CO2 is an estimate 

of the monetary value of impacts 

associated with a marginal change in 

CO2 emissions in a given year. The four 

SC–CO2 estimates are associated with 

different discount rates (model average 

at 2.5 percent discount rate, 3 percent, 

and 5 percent; 95th percentile at 3 

percent), and each increases over time. 

In this summary, the EPA provides the 

estimate of climate benefits associated 

with the SC–CO2 value deemed to be 

central in the current TSD: The model 

average at 3 percent discount rate. 

The EPA estimates that, in 2020, this 

proposal will yield monetized climate 

benefits (in 2011$) of approximately 

$2.8 billion for the rate-based approach 

and $3.3 billion for the mass-based 

approach (3 percent model average). For 

the rate-based approach, the air 

pollution health co-benefits in 2020 are 

estimated to be $0.7 billion to $1.8 

billion (2011$) for a 3 percent discount 

rate and $0.64 billion to $1.7 billion 

(2011$) for a 7 percent discount rate. 

For the mass-based approach, the air 

pollution health co-benefits in 2020 are 

estimated to be $2.0 billion to $4.8 

billion (2011$) for a 3 percent discount 

rate and $1.8 billion to $4.4 billion 

(2011$) for a 7 percent discount rate. 

The annual compliance costs estimated 

by IPM and inclusive of DS–EE program 

and participant costs and monitoring, 

reporting, and recordkeeping costs in 

2020, are approximately $2.5 billion for 

the rate-based approach and $1.4 billion 

for the mass-based approach (2011$). 

The quantified net benefits (the 

difference between monetized benefits 

and compliance costs) in 2020 are 

estimated to range from $1.0 billion to 

$2.1 billion (2011$) for the rate-based 

approach and from $3.9 billion to $6.7 

billion (2011$) for the mass-based 

approach, using a 3 percent discount 

rate (model average). 

The EPA estimates that, in 2025, the 

proposal will yield monetized climate 

benefits (in 2011$) of approximately $10 

billion for the rate-based approach and 

$12 billion for the mass-based approach 

(3 percent model average). For the ratebased approach, the air pollution health 

co-benefits in 2025 are estimated to be 

$7.4 billion to $18 billion (2011$) for a 

3 percent discount rate and $6.7 billion 

to $16 billion (2011$) for a 7 percent 

discount rate. For the mass-based 

approach, the air pollution health cobenefits in 2025 are estimated to be $7.1 

billion to $17 billion (2011$) for a 3 

percent discount rate and $6.5 billion to 

$16 billion (2011$) for a 7 percent 

discount rate. The annual compliance 

costs estimated by IPM and inclusive of 

DS–EE program and participant costs 

and MRR costs in 2025, are 

approximately $1.0 billion for the ratebased 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). 

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The EPA estimates that, in 2030, the 

proposal will yield monetized climate 

benefits (in 2011$) of approximately $20 

billion for the rate-based approach and 

$20 billion for the mass-based approach 

(3 percent model average). For the ratebased approach, the air pollution health 

co-benefits in 2030 are estimated to be 

$14 billion to $34 billion (2011$) for a 

3 percent discount rate and $13 billion 

to $31 billion (2011$) for a 7 percent 

discount rate. For the mass-based 

approach, the air pollution health cobenefits in 2030 are estimated to be $12 

billion to $28 billion (2011$) for a 3 

percent discount rate and $11 billion to 

$26 billion (2011$) for a 7 percent 

discount rate. The annual compliance 

costs estimated by IPM and inclusive of 

DS–EE program and participant costs 

and monitoring, reporting, and 

recordkeeping costs in 2030, are 

approximately $8.4 billion for the ratebased approach and $5.1 billion for the 

mass-based approach (2011$). The 

quantified net benefits (the difference 

between monetized benefits and 

compliance costs) in 2030 are estimated 

to range from $26 billion to $45 billion 

(2011$) for the rate-based approach and 

from $26 billion to $43 billion (2011$) 

for the mass-based approach, using a 3 

percent discount rate (model average). 

Table 18 and Table 19 of this 

preamble provide the estimates of the 

climate benefits, health co-benefits, 

compliance costs and net benefits of the 

proposal for rate-based and mass-based 

federal plan approaches, respectively. 

TABLE 18—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, AND NET BENEFITS FOR THE PROPOSAL IN

2020, 2025 AND 2030 UNDER THE RATE-BASED FEDERAL PLAN APPROACH

[Billions of 2011$] a

Rate-Based Approach 

2020 2025 2030 

Climate Benefits b

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 Co-benefits c ............................. $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 Costs d .......... $2.5 $1.0 $8.4 

Net Benefits e ................... $1.0 to $2.1 $1.0 to $2.0 $17 to $27 $16 to $25 $26 to $45 $25 to $43 

Non-Monetized Benefits ... Non-monetized climate benefits. 

Reductions in exposure to ambient NO2 and SO2. 

Reductions in mercury deposition. 

Ecosystem benefits associated with reductions in emissions of NOX, SO2, PM, and mercury. 

Visibility impairment. 

aAll are rounded to two significant figures, so figures may not sum. 

bThe 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 longlived and subsequent damages occur over many years. The benefit estimates in this table are based on the average SC–CO2 estimated for a 3 

percent discount rate. However, we emphasize the importance and value of considering the full range of SC–CO2 values. As shown in the RIA, 

climate benefits are also estimated using the other three SC–CO2 estimates (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). The SC–CO2 estimates are year-specific and increase over time. cThe air pollution health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions of SO2 and NOX. The 

range reflects the use of concentration-response functions from different epidemiology studies. The co-benefits do not include the benefits of reductions in directly emitted PM2.5. These additional benefits would increase overall benefits by a few percent based on the analyses conducted 

for the Clean Power Plan proposed rule. The reduction in premature fatalities each year accounts for over 98 percent of total monetized co-benefits from PM2.5 and ozone. These models assume that all fine particles, regardless of their chemical composition, are equally potent in causing

premature mortality because the scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type. d Costs are approximated by the compliance costs estimated using the IPM for this proposal and a discount rate of approximately 5 percent. 

This estimate includes monitoring, recordkeeping, and reporting costs and DS–EE program and participant costs. eThe 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. 

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65054 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Proposed Rules 

TABLE 19—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, AND NET BENEFITS FOR THE PROPOSAL IN

2020, 2025 AND 2030 UNDER THE MASS-BASED FEDERAL PLAN APPROACH

[Billions of 2011$] a

Mass-Based Approach 

2020 2025 2030 

Climate Benefits b

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 Co-benefits c ............................. $2.0 to $4.8 $1.8 to $4.4 $7.1 to $17 $6.5 to $16 $12 to $28 $11 to $26 

Compliance Costs d .......... $1.4 $3.0 $5.1 

Net Benefits e ................... $3.9 to $6.7 $3.7 to $6.3 $16 to $26 $15 to $24 $26 to $43 $25 to $40 

Non-Monetized Benefits ... Non-monetized climate benefits. 

Reductions in exposure to ambient NO2 and SO2. 

Reductions in mercury deposition. 

Ecosystem benefits associated with reductions in emissions of NOX, SO2, PM, and mercury. 

Visibility improvement. 

aAll are rounded to two significant figures, so figures may not sum. 

bThe 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 longlived and subsequent damages occur over many years. The benefit estimates in this table are based on the average SC–CO2 estimated for a 3 

percent discount rate. However, we emphasize the importance and value of considering the full range of SC–CO2 values. As shown in the RIA, 

climate benefits are also estimated using the other three SC–CO2 estimates (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). The SC–CO2 estimates are year-specific and increase over time. cThe air pollution health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions of SO2 and NOX. The 

co-benefits do not include the benefits of reductions in directly emitted PM2.5. These additional benefits would increase overall benefits by a few 

percent based on the analyses conducted for the Clean Power Plan proposed rule. The range reflects the use of concentration-response functions from different epidemiology studies. The reduction in premature fatalities each year accounts for over 98 percent of total monetized co-benefits from PM2.5 and ozone. These models assume that all fine particles, regardless of their chemical composition, are equally potent in causing

premature mortality because the scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type. d Costs are approximated by the compliance costs estimated using IPM for this proposal and a discount rate of approximately 5 percent. This 

estimate includes monitoring, recordkeeping, and reporting costs and DS–EE program and participant costs. eThe estimates of net benefits in this summary table are calculated using the global SC–CO2 at a 3 percent discount rate (model average). 

The RIA includes combined climate and health estimates based on additional discount rates. 

There are additional important 

benefits that the EPA could not 

monetize. Due to current data and 

modeling limitations, our estimates of 

the benefits from reducing CO2

emissions do not include important 

impacts like ocean acidification or 

potential tipping points in natural or 

managed ecosystems. Unquantified 

benefits also include climate benefits 

from reducing emissions of non-CO2

GHGs (e.g., nitrous oxide and methane) 

and co-benefits from reducing direct 

exposure to SO2, NOX, and HAP (e.g., 

mercury), as well as from reducing 

ecosystem effects and visibility 

impairment. Based upon the foregoing 

discussion, it remains clear that the 

benefits of this proposed action are 

substantial, and far exceed the costs. 

Additional details on benefits, costs, 

and net benefits estimates are provided 

in the RIA for this proposal. 

B. Paperwork Reduction Act (PRA) 

The information collection 

requirements in this rule have been 

submitted for approval to OMB under 

the PRA. The Information Collection 

Request (ICR) document prepared by the 

EPA has been assigned EPA ICR number 

2526.01. You can find a copy of the ICR 

in the docket for this rule, and it is 

briefly summarized here. The 

information collection requirements are 

not enforceable until approved by OMB. 

This rule does not directly impose 

specific requirements on state and U.S. 

territory governments with affected 

EGUs. The rule also does not impose 

specific requirements on tribal 

governments that have affected EGUs 

located in their area of Indian country. 

This rule does impose specific 

requirements on affected 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 (i.e., the Clean 

Power Plan) finalized on August 3, 

2015. The information collection 

requirements in this proposed rule have 

been submitted for approval to the 

Office of Management and Budget 

(OMB) under the Paperwork Reduction 

Act, 44 U.S.C. 3501 et seq. The ICR 

document prepared by the EPA has been 

assigned EPA ICR number 2526.01. You 

can find a copy of the ICR in the docket 

for this rule, and it is briefly 

summarized here. 

Aside from reading and 

understanding the rule, this proposed 

action would impose minimal new 

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information collection burden on 

affected EGUs beyond what those 

affected EGUs would already be subject 

to under the authorities of 40 CFR parts 

75 and 98. OMB has previously 

approved the information collection 

requirements contained in the existing 

part 75 and 98 regulations (40 CFR part 

75 and 40 CFR part 98) under the 

provisions of the Paperwork Reduction 

Act, 44 U.S.C. 3501 et seq. and has 

assigned OMB control numbers 2060– 

0626 and 2060–0629, respectively. 

Apart from certain reporting costs based 

on requirements in the NSPS General 

Provisions (40 CFR part 60, subpart A), 

which are mandatory for all owners/

operators subject to CAA section 111 

national emission standards, there are 

no new information collection costs, as 

the information required by this 

proposed rule is already collected and 

reported by other regulatory programs. 

The recordkeeping and reporting 

requirements are specifically authorized 

by CAA section 114 (42 U.S.C. 7414). 

All information submitted to the EPA 

pursuant to the recordkeeping and 

reporting requirements for which a 

claim of confidentiality is made is 

safeguarded according to agency 

policies set forth in 40 CFR part 2, 

subpart B. 

Although the EPA cannot determine 

at this time how many affected EGU 

respondents will submit information 

under the federal plan, the EPA has 

estimated an ‘‘upper bound’’ burden 

estimate for this ICR that estimates 

burden should every affected EGU read 

and understand the rule. This is the 

only potential respondent activity that 

would be required under the 3-year 

period following publication of the final 

federal plan, as there are no obligations 

to respond in this period. The results of 

this upper bound estimate of federal 

plan burden are presented below: 

Respondents/affected entities: 1,028. 

Respondents’ obligation to respond: 

Not applicable, no responses are 

required during the period covered by 

the ICR. 

Estimated number of respondents: 

Unknown at this time, but have 

assumed all affected entities are 

respondents for an upper bound 

estimate. 

Frequency of response: None, no 

responses are required during the period 

covered by the ICR. 

Total estimated burden: 17,133 hours 

(per year). Burden is defined at 5 CFR 

1320.3(b). 

Total estimated cost: $1,706,501 (per 

year). 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to, a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for the EPA’s regulations in 40 

CFR are listed in 40 CFR part 9. 

Submit your comments on the 

agency’s need for this information, the 

accuracy of the provided burden 

estimates, and any suggested methods 

for minimizing respondent burden to 

the EPA using the docket identified at 

the beginning of this rule. You may also 

send your ICR-related comments to 

OMB’s Office of Information and 

Regulatory Affairs via email to oria_

submissions@omb.eop.gov, Attention: 

Desk Officer for the EPA. Since OMB is 

required to make a decision concerning 

the ICR between 30 and 60 days after 

receipt, OMB must receive comments no 

later than November 23, 2015. The EPA 

will respond to any ICR-related 

comments in the final rule. 

C. Regulatory Flexibility Act (RFA) 

Pursuant to section 603 of the RFA, 

the EPA prepared an initial regulatory 

flexibility analysis (IRFA) that examines 

the impact of the proposed rule on small 

entities along with regulatory 

alternatives that could minimize that 

impact. The complete IRFA is available 

for review within the RIA in docket 

EPA–HQ–OAR–2015–0199 and is 

summarized here. 

The small entities subject to the 

requirements of this proposed rule may 

include privately-owned and publiclyowned entities, and rural electric 

cooperatives that are majority owners of 

affected EGUs. The EPA conducted this 

regulatory flexibility analysis at the 

highest level of ownership, evaluating 

parent entities with the largest share of 

ownership in at least one potentiallyaffected EGU included in EPA’s Base 

Case using the IPM v.5.15, used in the 

RIA for this proposed rule. This analysis 

drew on parsed unit-level estimates 

using IPM results for 2030. 

The EPA identified 223 potentially 

affected EGUs owned by 74 small 

entities included in 2030 projections 

from EPA’s IPM v.5.15. Fifty-nine of 

these potentially affected EGUs are 

projected to no longer be operating by 

2030 in the Base Case of EPA’s version 

of IPM. Twenty-four small entities are 

projected to have all of their potentially 

affected EGUs cease operation by 2030 

in this base case. 

The EPA estimated net compliance 

costs for individual EGUs for the 

proposed rule using components for 

operating and annualized capital costs, 

fuel costs, demand-side energy 

efficiency program costs, and revenue 

changes. This approach is consistent 

with previous proposed power sector 

regulations, but also adds the additional 

component of change in demand-side 

energy efficiency program costs. 

Investment in demand-side energy 

efficiency results in lower electricity 

demand, and consequently fewer 

emissions as production is reduced to 

meet the lower demand, an important 

emission-reduction strategy modeled in 

the rate-based and mass-based federal 

plan approaches. For this analysis, the 

EPA used the parsed unit-level 

estimates to estimate three of the four 

components of the net compliance cost 

equation using IPM outputs: The change 

in operating and annualized capital 

costs, the change in fuel costs, and the 

change in revenue, where all changes 

are estimated as the difference between 

the base case and federal plan scenario. 

These impacts were then summed for 

each small entity, adjusting for 

ownership share. An additional analysis 

was performed outside of EPA’s IPM 

model to estimate the change in 

demand-side energy efficiency program 

costs, based largely on IPM-projected 

outputs. 

As noted earlier, there are 74 small 

entities with potentially affected EGUs 

that are modeled in the IPM base case 

in 2030. Of these, 24 small entities are 

projected to withdraw all of their 

potentially affected EGUs from 

operation under base case conditions. 

This leaves 50 small entities with 

potentially affected EGUs that are 

projected to be generating electricity in 

2030. Under the rate-based federal plan 

approach, 7 of these 50 small entities 

are projected to withdraw all of their 

potentially affected EGUs from 

operation by 2030. Under the massbased federal plan approach, 5 of these 

50 small entities are projected withdraw 

all of their potentially affected EGUs 

from operation by 2030. 

Under the rate-based federal plan 

approach, 23 small entities are projected 

to incur net compliance costs greater 

than 3 percent of generation revenues 

from their potentially affected EGUs. In 

contrast, 9 entities are estimated to have 

net compliance cost savings greater than 

3 percent of their generation revenues 

from affected EGUs. Under the massbased federal plan approach, 21 small 

entities are projected to incur net 

compliance costs greater than 3 percent 

of generation revenues from their 

potentially affected EGUs. In contrast, 

11 entities are estimated to have net 

compliance cost savings greater than 3 

percent of generation revenues from 

their affected EGUs. 

There are uncertainties and 

limitations in this analysis that may 

result in estimates that diverge from 

what we might see in reality. For 

example, at the time of this proposal, 

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the EPA has no information on whether 

any or how many states will require a 

federal plan. The rate-based and massbased federal plan approaches analyzed 

in this IRFA are based on a scenario 

where all states of the contiguous 

United States will be regulated under a 

federal plan. Another factor to consider 

is that entities operating in regulated or 

cost-of-service markets are likely able to 

recover compliance costs through rate 

adjustments; as a result these costs can 

be viewed as likely being over-estimates 

for this set of utilities. Other 

uncertainties and data limitations exist 

and are described in the complete IRFA 

available for review within the RIA for 

this proposal. 

As discussed earlier in this preamble, 

the reporting, recordkeeping and other 

compliance requirements are most 

likely covered under 40 CFR part 75 and 

part 98 programs for affected EGUs. 

Therefore, only a marginal additional 

cost is expected for the monitoring, 

reporting and recordkeeping 

requirements of the proposed federal 

plan for affected EGUs. 

Owners of affected EGUs may be 

subject to other related rules. For 

example, on September 20, 2013, the 

EPA proposed carbon pollution 

standards for new fossil fuel fired EGUs. 

On June 2, 2014, the EPA proposed 

carbon pollution standards for modified 

and reconstructed fossil fuel-fired EGUs, 

in addition to the Clean Power Plan 

EGs, to cut carbon pollution from 

existing fossil fuel-fired EGUs. These 

existing EGUs are, or will be, potentially 

impacted by several other recently 

finalized EPA rules. On February 16, 

2012, the EPA issued the mercury and 

air toxics standards (MATS) rule (77 FR 

9304) to reduce emissions of toxic air 

pollutants from new and existing coaland oil-fired EGUs. On May 19, 2014, 

the EPA issued a final rule under 

section 316(b) of the Clean Water Act 

(33 U.S.C. 1326(b)). This rule establishes 

new standards to reduce injury and 

death of fish and other aquatic life 

caused by cooling water intake 

structures at existing power plants and 

manufacturing facilities. On June 18, 

2014 (79 FR 34830), the EPA 

promulgated the stream electric effluent 

limitation guidelines (SE ELG) rule to 

strengthen the controls on discharges 

from certain steam electric power 

plants. On April 17, 2015 (80 FR 21302), 

the EPA promulgated the coal 

combustion residuals (CCR) rule, which 

establishes technical requirements for 

CCR landfills and surface 

impoundments under subtitle D of the 

Resource Conservation and Recovery 

Act (RCRA), the nation’s primary law 

for regulating solid waste. 

As required by section 609(b) of the 

RFA, the EPA also convened a Small 

Business Advocacy Review (SBAR) 

Panel to obtain advice and 

recommendations from small entity 

representatives that potentially would 

be subject to the rule’s requirements. 

The SBAR Panel evaluated the 

assembled materials and small-entity 

comments on issues related to elements 

of an IRFA. A copy of the full SBAR 

Panel Report is available in the 

rulemaking docket. 

The EPA also considered whether the 

separate changes that we are proposing 

to make, as explained in section VII of 

this preamble, to the framework 

regulations in subpart B of part 60 of the 

CAA regulations would have any 

impacts on small entities. Since these 

changes only modify and enhance the 

procedures that the Administrator will 

follow in processing state plans and 

promulgating a federal plan, and do not 

alter the rules or requirements that 

states or regulated entities must follow, 

the agency does not believe that there 

will be economic impacts on small 

entities from this portion of this 

proposal. After considering the 

economic impacts of the proposed 

changes to 40 CFR 60.27, I certify those 

changes will not have a significant 

economic impact on a substantial 

number of small entities. 

D. Unfunded Mandates Reform Act 

(UMRA) 

This action contains a federal 

mandate under UMRA, 2 U.S.C. 1531– 

1538, that could potentially result in 

expenditures of $100 million or more 

for state, local, and tribal governments, 

in the aggregate, or the private sector in 

any 1 year. This federal plan will apply 

only to those affected EGUs located in 

states that do not submit approvable 

state plans, which is a subset of the 

EGUs considered in the RIA for the final 

EGs (see RIA for this proposal for 

further discussion of impacts). Because 

it is impossible to determine at this time 

which states might be ultimately subject 

to a federal plan, the EPA cannot 

determine whether this rule, when 

finalized, will be subject to UMRA. 

However, as noted below, the agency 

has done substantial outreach to 

government entities as part of both the 

federal plan and the related CAA 

section 111(d) rulemaking. Further, 

regardless of whether the EPA does 

determine that this action ultimately 

meets the UMRA threshold, the agency 

intends to do additional outreach with 

government entities between now and 

the final rule. Additionally, the EPA has 

determined that this action is not 

subject to the requirements of section 

203 of UMRA because it contains no 

regulatory requirements that might 

significantly or uniquely affect small 

governments. 

Nevertheless, the EPA is aware that 

there is substantial interest in this rule 

among small entities (e.g., municipal 

and rural electric cooperatives). In light 

of this interest, prior to this action, the 

EPA sought early input from 

representatives of small entities while 

formulating the provisions of the 

proposed regulation. Such outreach is 

also consistent with the President’s 

January 18, 2011 Memorandum on 

Regulatory Flexibility, Small Business, 

and Job Creation, which emphasizes the 

important role small businesses play in 

the American economy. This outreach 

process has enabled the EPA to hear 

directly from these representatives, as 

the EPA developed the rule about how 

the EPA should approach the complex 

question of how to apply section 111 of 

the CAA to the regulation of GHGs from 

these source categories. We invite 

comments on all aspects of this proposal 

and its impacts, including potential 

adverse impacts, on small entities. 

E. Executive Order 13132: Federalism 

The EPA believes that this proposed 

rule may be of significant interest to 

state and local governments due to its 

relationship with the Clean Power Plan 

EGs. Therefore, the EPA has determined 

that consultations with state and local 

governments conducted during the 

Clean Power Plan EGs development 

process are also relevant to this 

proposed rule. Consistent with the 

EPA’s policy to promote 

communications between the EPA and 

state and local governments, the EPA 

consulted with state and local officials 

early in the process of developing the 

Clean Power Plan EGs to permit them to 

have meaningful and timely input into 

its development. As described in the 

Federalism discussion in the preamble 

to the proposed standards of 

performance for GHG emissions from 

new EGUs (79 FR 1501; January 8, 

2014), the EPA consulted with state and 

local officials in the process of 

developing the proposed standards 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 Clean Power Plan EGs, as 

required by section 6(b) of Executive 

Order 13132. In the spirit of Executive 

Order 13132, and consistent with the 

EPA’s policy to promote 

communications between the EPA and 

state and local governments, the EPA 

specifically solicits comment on this 

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proposed action from state and local 

officials. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This proposed action has tribal 

implications. However, it will neither 

impose substantial direct compliance 

costs on federally recognized tribal 

governments, nor preempt tribal law. 

The EGUs potentially impacted by this 

proposed rulemaking located on Indian 

reservations are primarily owned by 

private entities, and in one case, 

partially owned by an agency of the U.S. 

government. As a result, the tribes on 

whose areas of Indian country those 

units are located will not be directly 

impacted by any costs of complying 

with this proposed rulemaking incurred 

by the owners/operators of those units. 

There would only be tribal implications 

in regards to compliance costs 

associated with this proposed 

rulemaking in the case where a tribal 

government has an ownership interest 

in a potentially affected EGU. A tribal 

government could also incur costs in the 

event that it seeks and is given 

delegated authority to enforce the 

federal plan proposed in this 

rulemaking. The EPA has, nevertheless, 

offered consultation to the tribes on 

whose areas of Indian country the units 

are located. As part of its general 

outreach to tribes regarding this 

proposed rulemaking, the EPA received 

feedback from a number of tribes 

regarding the potential overall economic 

impact that both the proposed Clean 

Power Plan and a proposed federal plan 

rulemaking may have on them. In these 

instances, the EPA has reached out to 

these tribes and as part of the 

consultation on the Clean Power Plan 

engaged with them on their concerns 

regarding a potential federal plan. 

The EPA has conducted consultation 

with tribes on the Clean Power Plan and 

the Supplemental Proposal for the Clean 

Power Plan and will offer all tribes 

consultation on this proposed action. 

The EPA held consultations with tribes 

on the Clean Power Plan in the fall of 

2014 before the agency issued its 

Supplemental Proposal for Indian 

country and U.S. Territories. 

Additionally, the EPA held 

consultations for tribes shortly 

following the release of the 

supplemental proposal. The agency also 

held a public hearing on the 

supplemental proposal on November 19, 

2014, in Phoenix, Arizona. At the public 

hearing the agency received oral 

comments from community members 

representing a number of tribes and a 

number of tribal officials. The agency 

also conducted consultations with tribes 

in the spring and summer of 2015. An 

overview of the consultations provided 

as part of the Clean Power Plan is 

available in section XII.F of the final 

EGs. 

Additionally, the EPA engaged in 

meaningful dialogue with tribal 

stakeholders to obtain their feedback in 

the pre-proposal stages of this 

rulemaking. We provided an update on 

this proposed rulemaking on the May 

28, 2015, National Tribal Air 

Association and the EPA Air Policy call. 

Staff attended the National Tribal 

Forum conference on May 20, 2015 and 

provided an overview of the Clean 

Power Plan and explained that the 

agency would be proposing a federal 

plan. 

Consistent with previous rulemakings 

impacting the power sector, there is 

significant tribal interest in these 

rulemakings because of the potential 

indirect impacts that rules such as the 

Clean Power Plan and this proposed 

federal plan may have on tribes. The 

EPA specifically solicits additional 

feedback from tribal officials on all 

aspects of this proposed rulemaking, 

including whether tribes whose areas of 

Indian country contain affected EGU(s) 

are interested in developing their own 

plan implementing the final EGs. 

Additionally, tribal stakeholders will be 

included in the outreach that the agency 

will be conducting with those 

communities already overburdened by 

pollution, which are often low-income 

communities, communities of color, and 

indigenous communities. The actions 

that the agency will be taking are 

outlined in section IX of this preamble. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

The EPA interprets EO 13045 (62 FR 

19885; April 23, 1997) as applying to 

those regulatory actions that concern 

health or safety risks, such that the 

analysis required under section 5–501 of 

the Order has the potential to influence 

the regulation. This action is not subject 

to EO 13045 because it does not involve 

decisions on environmental health or 

safety risks that may disproportionately 

affect children. The EPA believes that 

the CO2 emission reductions resulting 

from implementation of the proposed 

federal plan, as well as substantial 

ozone and PM2.5 emission reductions as 

a cobenefit, would further improve 

children’s health. 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action, which is a significant 

regulatory action under EO 12866, is 

likely to have a significant effect on the 

supply, distribution, or use of energy. 

The EPA has prepared a Statement of 

Energy Effects for this action as follows. 

We estimate a 1 to 2 percent change in 

retail electricity prices on average across 

the contiguous United States in 2025, 

and a 22 to 23 percent reduction in coalfired 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) and 1 CFR 

Part 51 

This proposed action involves 

technical standards. The EPA proposes 

to recognize ANSI accreditation under 

ISO 14065 for GHG validation and 

verification bodies as a component of 

accreditation of independent verifiers 

under both proposed federal plan 

approachs. The EPA also proposes that 

net energy output measurements must 

be performed using 0.2 accuracy class 

electricity metering instrumentation and 

calibration procedures as specified 

under ANSI Standards No. C12.20. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629; 

February 16, 1994) establishes federal 

executive policy on environmental 

justice (EJ). Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make EJ part of their mission by 

identifying and addressing, as 

appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. The 

EPA defines EJ as the fair treatment and 

meaningful involvement of all people 

regardless of race, color, national origin, 

or income with respect to the 

development, implementation, and 

enforcement of environmental laws, 

regulations, and policies. The EPA has 

this goal for all communities and 

persons across this Nation. It will be 

achieved when everyone enjoys the 

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154Melillo, Jerry M., Terese (T.C.) Richmond, and 

Gary W. Yohe, Eds., 2014: Climate Change Impacts 

in the United States: The Third National Climate 

Assessment. U.S. Global Change Research Program, 

841 pp. 

IPCC, 2014: Climate Change 2014: Impacts, 

Adaptation, and Vulnerability. Part A: Global and 

Sectoral Aspects. Contribution of Working Group II 

to the Fifth Assessment Report of the 

Intergovernmental Panel on Climate Change [Field, 

C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. 

Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. 

Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. 

Levy, S. MacCracken, P.R. Mastrandrea, and L.L. 

White (eds.)]. Cambridge University Press, 1132 pp. 

IPCC, 2014: Climate Change 2014: Impacts, 

Adaptation, and Vulnerability. Part B: Regional 

Aspects. Contribution of Working Group II to the 

Fifth Assessment Report of the Intergovernmental 

Panel on Climate Change [Barros, V.R., C.B. Field, 

D.J. Dokken, M.D. Mastrandrea, K.J. Mach, T.E. 

Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. 

Genova, B. Girma, E.S. Kissel, A.N. Levy, S. 

MacCracken, P.R. Mastrandrea, and L.L. White 

(eds.)]. Cambridge University Press, 688 pp. 

155 ‘‘National Ambient Air Quality Standards for 

Particulate Matter, Final Rule,’’ 78 FR 3086 (January 

15, 2013). 

156U.S. Environmental Protection Agency (U.S. 

EPA). 2009. Integrated Science Assessment for 

Particulate Matter (Final Report). EPA–600–R–08– 

139F. National Center for Environmental 

Assessment—RTP Division. December. Available on 

the Internet at http://www.cfpub.epa.gov/si/si_

public_record_Report.cfm?dirEntryId=216546. 

157 Guidance on Considering Environmental 

Justice During the Development of Regulatory 

Actions. http://www.epa.gov/environmentaljustice/

resources/policy/considering-ej-in-rulemakingguide-final.pdf. May 2015. 

same degree of protection from 

environmental and health hazards and 

equal access to the decision-making 

process to have a healthy environment 

in which to live, learn, and work. 

Leading up to this rulemaking the 

EPA summarized the public health and 

welfare effects of GHG emissions in its 

2009 Endangerment Finding. As part of 

the Endangerment Finding, the 

Administrator considered climate 

change risks to minority populations 

and low-income populations, finding 

that certain parts of the population may 

be especially vulnerable based on their 

characteristics or circumstances. 

Populations that were found to be 

particularly vulnerable to climate 

change risks include the poor, the 

elderly, the very young, those already in 

poor health, the disabled, those living 

alone, and/or indigenous populations 

dependent on one or a few resources. 

See sections X.F and X.G of this 

preamble, above, where the EPA 

discusses Consultation and 

Coordination with Tribal Governments 

and Protection of Children. The 

Administrator placed weight on the fact 

that certain groups, including children, 

the elderly, and the poor, are most 

vulnerable to climate-related health 

effects. 

The record for the 2009 

Endangerment Finding summarizes the 

strong scientific evidence in the major 

assessment reports by the U.S. Global 

Change Research Program, the 

Intergovernmental Panel on Climate 

Change (IPCC), and the National 

Research Council of the National 

Academies that the potential impacts of 

climate change raise EJ issues. These 

reports concluded that poor 

communities can be especially 

vulnerable to climate change impacts 

because they tend to have more limited 

adaptive capacities and are more 

dependent on climate-sensitive 

resources such as local water and food 

supplies. In addition, Native American 

tribal communities possess unique 

vulnerabilities to climate change, 

particularly those impacted by 

degradation of natural and cultural 

resources within established reservation 

boundaries and threats to traditional 

subsistence lifestyles. Tribal 

communities whose health, economic 

well-being, and cultural traditions that 

depend upon the natural environment 

will likely be affected by the 

degradation of ecosystem goods and 

services associated with climate change. 

The 2009 Endangerment Finding record 

also specifically noted that Southwest 

native cultures are especially vulnerable 

to water quality and availability 

impacts. Native Alaskan communities 

are already experiencing disruptive 

impacts, including coastal erosion and 

shifts in the range or abundance of wild 

species crucial to their livelihoods and 

well-being. 

The most recent assessments continue 

to strengthen scientific understanding of 

climate change risks to minority 

populations and low-income 

populations in the United States.154 The 

new assessment literature provides 

more detailed findings regarding these 

populations’ vulnerabilities and 

projected impacts they may experience. 

In addition, the most recent assessment 

reports provide new information on 

how some communities of color may be 

uniquely vulnerable to climate change 

health impacts in the 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 EJ 

concerns. Existing health disparities and 

other inequities in these communities 

increase their vulnerability to the health 

effects of climate change. In addition, 

assessment reports also find that climate 

change poses particular threats to 

health, well-being, and ways of life of 

indigenous peoples in the United States. 

As the scientific literature presented 

above and as the 2009 Endangerment 

Finding illustrates, low-income 

populations and some communities of 

color are especially vulnerable to the 

health and other adverse impacts of 

climate change. The EPA believes that 

communities will benefit from this 

proposed federal plan because this 

action directly addresses the impacts of 

climate change by limiting GHG 

emissions through the establishment of 

CO2 emission standards for existing 

affected fossil fuel-fired EGUs. 

In addition to reducing CO2

emissions, the guidelines finalized in 

this rulemaking would reduce other 

emissions from affected EGUs that 

reduce generation due to higher 

adoption of EE and RE. These emission 

reductions will include SO2 and NOX, 

which form ambient PM2.5 and ozone in 

the atmosphere, and HAP, such as 

mercury and hydrochloric acid. In the 

final rule revising the annual PM2.5

NAAQS,155 the EPA identified lowincome populations as being a 

vulnerable population for experiencing 

adverse health effects related to PM 

exposures. Low-income populations 

have been generally found to have a 

higher prevalence of pre-existing 

diseases, limited access to medical 

treatment, and increased nutritional 

deficiencies, which can increase this 

population’s susceptibility to PMrelated effects.156 In areas where this 

rulemaking reduces exposure to PM2.5, 

ozone, and methylmercury, low-income 

populations will also benefit from such 

emission reductions. The RIA for this 

rulemaking, included in the docket for 

this rulemaking, provides additional 

information regarding the health and 

ecosystem effects associated with these 

emission reductions. 

Additionally, as outlined in the 

community and EJ considerations 

section IX of this preamble, the EPA has 

taken a number of actions to help ensure 

that this action will not have potential 

disproportionately high and adverse 

human health or environmental effects 

on vulnerable communities. The EPA 

consulted its May 2015, Guidance on 

Considering Environmental Justice 

During the Development of Regulatory 

Actions, when determining what actions 

to take.157 As described in section IX of 

this preamble (community and EJ 

considerations), the EPA also conducted 

a proximity analysis, which is available 

in the docket of this rulemaking and is 

discussed in section IX of this preamble. 

Additionally, as outlined in sections I 

and IX of this preamble the EPA has 

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engaged meaningfully with 

communities throughout the 

development of the Clean Power Plan 

and has devised a robust outreach 

strategy for continual engagement 

throughout this rulemaking. 

List of Subjects 

40 CFR Part 60 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Intergovernmental 

relations. 

40 CFR Part 62 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Incorporation by 

reference, Intergovernmental relations, 

Reporting and recordkeeping 

requirements. 

40 CFR Part 78 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control. 

Dated: August 3, 2015. 

Gina McCarthy, 

Administrator. 

For the reasons stated in the 

preamble, title 40, chapter I, parts 60, 

62, and 78 of the Code of the Federal 

Regulations is amended as follows: 

PART 60—STANDARDS OF 

PERFORMANCE FOR NEW 

STATIONARY SOURCES 

■ 1. The authority citation for part 60 

continues to read as follows: 

Authority: 42 U.S.C. 7401 et seq. 

■ 2. Section 60.27 is amended by: 

■ a. Revising paragraphs (b), (c) 

introductory text, and (c)(1); 

■ b. Removing and reserving paragraph 

(c)(2); 

■ c. Revising paragraphs (c)(3), (d), and 

(e)(1); and 

■ d. Adding paragraphs (g) through (k). 

The revisions and additions read as 

follows: 

§ 60.27 Actions by the Administrator. 

* * * * * 

(b) After receipt of a complete plan or 

complete plan revision, the 

Administrator will propose the plan or 

revision for approval or disapproval. 

The Administrator shall, within 12 

months after the date on which the 

submission of a complete plan or 

complete plan revision is received, 

approve or disapprove such plan or 

revision, or each portion thereof. 

(c) The Administrator shall 

promulgate a federal plan within 12 

months after the date the Administrator: 

(1) Finds the State failed to submit a 

complete plan or complete plan revision 

within the time prescribed; or 

* * * * * 

(3) Disapproves the State plan or plan 

revision or any portion thereof, as 

unsatisfactory because the requirements 

of this subpart and the applicable 

emission guidelines have not been met. 

(d) The Administrator will 

promulgate the regulations under 

paragraph (c) of this section for all or a 

portion of a federal plan, with such 

modifications as may be appropriate, 

unless, prior to such promulgation, the 

State has adopted and submitted a plan 

or plan revision which the 

Administrator approves. After the 

promulgation of a federal plan, the 

Administrator may approve a State plan 

or plan revision or portion thereof and 

withdraw all or a portion of the federal 

plan. 

(e)(1) Except as provided in paragraph 

(e)(2) of this section, regulations 

promulgated by the Administrator 

under this section will prescribe 

emission standards of the same 

stringency as the corresponding 

emission guideline(s) specified in the 

final guideline document published 

under § 60.22(a) and will require final 

compliance with such standards as 

expeditiously as practicable but no later 

than the times specified in the guideline 

document. 

* * * * * 

(g) Completeness criteria—(1) 

General. Within 60 days of the 

Administrator’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 for completeness 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. Where the Administrator 

determines that a plan submission does 

not meet the minimum criteria of this 

paragraph (g), the State will be treated 

as not having made the submission. 

(2) Administrative criteria. In order to 

be complete, a State plan must contain 

each of the following administrative 

criteria: 

(i) A formal letter of submittal from 

the Governor or her designee requesting 

EPA approval of the plan or revision 

thereof; 

(ii) Evidence that the State has 

adopted the plan in the state code or 

body of regulations. That evidence must 

include the date of adoption or final 

issuance as well as the effective date of 

the plan, if different from the adoption/ 

issuance date; 

(iii) Evidence that the State has the 

necessary legal authority under state 

law to adopt and implement the plan; 

(iv) A copy of the actual regulation, or 

document submitted for approval and 

incorporation by reference into the plan. 

The submittal must be a copy of the 

official state regulation or 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 or 

document must, 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 

must indicate the changes made (for 

example, by redline/strikethrough) to 

the approved plan; 

(v) Evidence that the State followed 

all of the procedural requirements of the 

state’s laws and constitution in 

conducting and completing the 

adoption and issuance of the plan; 

(vi) Evidence that public notice was 

given of the proposed change with 

procedures consistent with the 

requirements of § 60.23, including the 

date of publication of such notice; 

(vii) 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 § 60.23; 

(viii) Compilation of public comments 

and the State’s response thereto; and 

(ix) Such other criteria for 

completeness as may be specified by the 

Administrator under the applicable 

emission guidelines. 

(3) Technical criteria. In order to be 

complete, a State plan must contain 

each of the following technical criteria: 

(i) Description of the plan approach 

and geographic scope; 

(ii) Identification of each affected 

source, identification of emission 

standards for the affected sources, and 

monitoring, recordkeeping and 

reporting requirements that will 

determine compliance by each affected 

source; 

(iii) Identification of compliance 

schedules and/or increments of 

progress; 

(iv) Demonstration that the State plan 

submittal is projected to achieve 

emissions performance under the 

applicable emission guidelines; 

(v) Documentation of state 

recordkeeping and reporting 

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requirements to determine the 

performance of the plan as a whole; and 

(vi) Demonstration that each emission 

standard is quantifiable, nonduplicative, permanent, verifiable, and 

enforceable. 

(4) Parallel processing. A State may 

submit a State plan prior to actual 

adoption by the State in order to 

expedite review and provide an 

opportunity for the State to consider 

EPA comments prior to submission of a 

final plan for final review and action. 

Under these circumstances, the 

following exceptions to the criteria in 

this paragraph apply to plans submitted 

explicitly for parallel processing: 

(i) The letter required by paragraph 

(g)(2)(i) of this section must request that 

EPA propose approval of the proposed 

plan by parallel processing; 

(ii) In lieu of paragraph (g)(2)(ii) of 

this section the State must submit a 

schedule for final adoption or issuance 

of the plan; 

(iii) In lieu of paragraph (g)(2)(iv) of 

this section the plan must include a 

copy of the proposed/draft regulation or 

document, including indication of the 

proposed changes to be made to the 

existing approved plan, where 

applicable; and 

(iv) The requirements of paragraphs 

(g)(2)(v) through (ix) of this section do 

not apply to plans submitted for parallel 

processing. The exceptions granted in 

the preceding sentence apply only to 

EPA’s determination of proposed action 

and all requirements of paragraph (g)(2) 

of this section must be met prior to 

publication of EPA’s final determination 

of plan approvability. 

(h) Full and partial approval and 

disapproval. If a portion of the plan 

revision meets all the applicable 

requirements of this chapter, the 

Administrator may approve the plan 

revision in part and disapprove the plan 

revision in part. The Administrator may 

authorize partial plan submissions in 

conjunction with a federal plan, where 

in combination, the federal and State 

plans constitute a complete and 

approvable plan meeting all of the 

requirements of this subpart and the 

applicable emissions guidelines. 

(i) Conditional approval. The 

Administrator may approve a plan or a 

plan revision based on a commitment of 

the State, by a date certain established 

by the Administrator, to adopt specific 

enforceable measures, review and revise 

if appropriate State plans, or otherwise 

commit to making changes in the State’s 

plan necessary to meet the requirements 

of the applicable emission guidelines. 

Any such conditional approval 

automatically converts to a disapproval 

if the State fails to comply with such 

commitment by the date certain 

established by the Administrator. 

(j) Calls for plan revisions. Whenever 

the Administrator finds that the 

applicable plan is substantially 

inadequate to meet the requirements of 

the applicable emission guidelines, to 

provide for the implementation of such 

plan, or to otherwise comply with any 

requirement of the Clean Air Act, the 

Administrator must require the State to 

revise the plan as necessary to correct 

such inadequacies. The Administrator 

must notify the State of the 

inadequacies, and may establish 

reasonable deadlines (not to exceed 18 

months after the date of such notice) for 

the submission of such plan revisions. 

Such findings and notice must be 

public. Any finding under this 

paragraph shall, to the extent the 

Administrator deems appropriate, 

subject the State to the requirements of 

this part to which the State was subject 

when it developed and submitted the 

plan for which such finding was made, 

except that the Administrator may 

adjust any dates applicable under such 

requirements as appropriate. 

(k) Error corrections. Whenever the 

Administrator determines that the 

Administrator’s action approving, 

disapproving, or promulgating any plan 

or plan revision (or portion thereof) was 

in error, the Administrator may in the 

same manner as the approval, 

disapproval, or promulgation revise 

such action as appropriate without 

requiring any further submission from 

the State. Such determination and the 

basis thereof shall be provided to the 

State and public. 

PART 62—APPROVAL AND 

PROMULGATION OF STATE PLANS 

FOR DESIGNATED FACILITIES AND 

POLLUTANTS 

■ 3. The authority citation for part 62 

continues to read as follows: 

Authority: 42 U.S.C. 7401 et seq. 

■ 4. Add subpart MMM to read as 

follows: 

Subpart MMM—Greenhouse Gas Emissions 

Mass-based Model Trading Rule for Electric 

Utility Generating Units That Commenced 

Construction on or Before January 8, 2014 

Introduction 

Sec. 

62.16205 What is the purpose of this 

subpart? 

Applicability of This Subpart 

62.16210 Am I subject to this subpart? 

62.16215 What requirements apply to 

affected EGUs that retire? 

General Requirements 

62.16220 What requirements must I comply 

with? 

62.16225 How should I compute time under 

the CO2 Mass-based Trading Program? 

62.16230 What are the administrative 

appeal procedures? 

62.16231 How will the Clean Energy 

Incentive Program be administered 

under the federal plan? 

Emission Goals, Set-Asides, and Allowance 

Allocations 

62.16235 What are the statewide massbased emission goals, renewable energy 

set-asides, output-based set-asides, and 

Clean Energy Incentive Program early 

action set-asides? 

62.16240 When are allowances allocated? 

62.16245 How are set-aside allowances 

allocated? 

62.16250 What is the process for revocation 

of qualification status of an eligible 

resource? 

62.16255 What is the process for error 

adjustments or misstatement, and 

suspension of allowance issuance? 

Evaluation Measurement and Verification 

Plans, Monitoring and Verification Reports, 

and Verification 

62.16260 What are the requirements for 

evaluation, measurement and 

verification plans for eligible resources? 

62.16265 What are the requirements for 

monitoring and verification reports for 

eligible resources? 

62.16270 What are the requirements for 

verification reports? 

62.16275 What is the accreditation 

procedure for independent verifiers? 

62.16280 What are the procedures 

accredited independent verifiers must 

follow to avoid conflict of interest? 

62.16285 What is the process for the 

revocation of accreditation status for an 

independent verifier? 

Designated Representatives 

62.16290 How are designated 

representatives and alternate designated 

representatives authorized and what role 

do authorized designated representatives 

and alternate designated representatives 

play? 

62.16295 What responsibilities do 

designated representatives and alternate 

designated representatives hold? 

62.16300 What are the processes for 

changing designated representatives, 

alternate designated representatives, 

owners and operators, and affected EGUs 

at the facility? 

62.16305 What must be included in a 

certificate of representation? 

62.16310 What is the Administrator’s role 

in objections concerning designated 

representatives and alternate designated 

representatives? 

62.16315 What process must designated 

representatives and alternate designated 

representatives follow to delegate their 

authority? 

Monitoring, Recordkeeping, Reporting 

62.16320 How are compliance accounts and 

general accounts established? 

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62.16325 When will CO2 allowances be 

recorded in compliance accounts? 

62.16330 How must transfers of CO2

allowances be submitted? 

62.16335 When will CO2 allowance 

transfers be recorded? 

62.16340 How will deductions for 

compliance with a CO2 emission 

standard occur? 

62.16345 What monitoring requirements 

must I comply with? 

62.16350 May I bank CO2 annual 

allowances for future use or transfer? 

62.16355 How does the Administrator 

process account errors? 

62.16360 What are my reporting, 

notification and submission 

requirements? 

62.16365 What are my recordkeeping 

requirements? 

62.16370 What actions may the 

Administrator take on submissions? 

Definitions 

62.16375 What definitions apply to this 

subpart? 

62.16380 What measurements, 

abbreviations, and acronyms apply to 

this subpart? 

Subpart MMM—Greenhouse Gas 

Emissions Mass-based Model Trading 

Rule for Electric Utility Generating 

Units That Commenced Construction 

on or Before January 8, 2014 

Introduction 

§ 62.16205 What is the purpose of this 

subpart? 

(a) This subpart sets forth the 

requirements for the Clean Power Plan 

(CPP) CO2 Mass-based Trading Program, 

under section 111 of the Clean Air Act 

and subpart UUUU of part 60 of this 

chapter, as a means of meeting emission 

guidelines limiting greenhouse gas 

emissions from an affected steam 

generating unit, integrated gasification 

combined cycle (IGCC), or stationary 

combustion turbine. 

(b) The pollutants regulated by this 

subpart are greenhouse gases. The 

greenhouse gas limitations in this 

subpart are in the form of an emission 

standard for carbon dioxide (CO2). 

(c) PSD and title V thresholds for 

greenhouse gases. (1) For the purposes 

of § 51.166(b)(49)(ii) of this chapter, 

with respect to GHG emissions from 

affected facilities, the ‘‘pollutant that is 

subject to the standard promulgated 

under section 111 of the Act’’ is 

considered to be the pollutant that 

otherwise is subject to regulation under 

the Act as defined in § 51.166(b)(48) and 

in any state implementation plan 

approved by the EPA that is interpreted 

to incorporate, or specifically 

incorporates, § 51.166(b)(48) of this 

chapter. 

(2) For the purposes of 

§ 52.21(b)(50)(ii) of this chapter, with 

respect to GHG emissions from affected 

facilities, the ‘‘pollutant that is subject 

to the standard promulgated under 

section 111 of the Act’’ is considered to 

be the pollutant that otherwise is subject 

to regulation under the Act as defined 

in § 52.21(b)(49) of this chapter. 

(3) For the purposes of § 70.2 of this 

chapter, with respect to greenhouse gas 

emissions from affected facilities, the 

‘‘pollutant that is subject to any 

standard promulgated under section 111 

of the Act’’ is considered to be the 

pollutant that otherwise is ‘‘subject to 

regulation’’ as defined in § 70.2 of this 

chapter. 

(4) For the purposes of § 71.2 of this 

chapter, with respect to greenhouse gas 

emissions from affected facilities, the 

‘‘pollutant that is subject to any 

standard promulgated under section 111 

of the Act’’ is considered to be the 

pollutant that otherwise is ‘‘subject to 

regulation’’ as defined in § 71.2 of this 

chapter. 

Applicability of this Subpart 

§ 62.16210 Am I subject to this subpart? 

(a) You are subject to this subpart if 

you are the owner or operator of an 

affected electric generating unit (EGU) 

located within a State that has 

incorporated by reference this subpart 

as a State plan, or portion of a State 

plan, that has been approved by the 

Administrator and is effective under 

subpart UUUU of part 60 of this chapter, 

or if this subpart is promulgated and 

effective as a federal plan in your State 

under part 62 of this chapter. 

(b) An affected EGU is any steam 

generating unit, IGCC, or stationary 

combustion turbine that meets the 

applicability requirements in 

§§ 60.5840(b) and 60.5845 of this 

chapter. 

§ 62.16215 What requirements apply to 

affected EGUs that retire? 

(a) Exemption. (1) Any affected EGU 

that is permanently retired as defined in 

§ 62.16375 is exempt from 

§§ 62.16220(c)(1) [CO2 Emissions 

Requirements], 62.16340 [Compliance 

Requirements], 62.16345 [Monitoring], 

62.16360 [Reporting], and 62.16365 

[Recordkeeping]. 

(2) The exemption under paragraph 

(a)(1) of this section will become 

effective on the first day of the 

compliance period immediately 

following the compliance period in 

which the retirement took effect. Within 

30 days of the affected EGU’s permanent 

retirement, the designated 

representative must submit a statement 

to the Administrator. The statement 

must state, in a format prescribed by the 

Administrator, that the affected EGU 

was permanently retired on a specified 

date and will comply with the 

requirements of paragraph (b) of this 

section. 

(b) Special provisions. (1) An affected 

EGU exempt under paragraph (a) of this 

section must not emit any CO2, starting 

on the date that the exemption takes 

effect. 

(2) For a period of 5 years from the 

date the records are created, the owners 

and operators of an affected EGU 

exempt under paragraph (a) of this 

section must retain, at the facility that 

includes the unit, records demonstrating 

that the affected EGU is permanently 

retired. The 5-year period for keeping 

records may be extended for cause, at 

any time before the end of the period, 

in writing by the Administrator. The 

owners and operators bear the burden of 

proof that the affected EGU is 

permanently retired. 

(3) The owners and operators and, to 

the extent applicable, the designated 

representative of an affected EGU 

exempt under paragraph (a) of this 

section must comply with the 

requirements of the CO2 Mass-based 

Trading Program accruing during any 

compliance periods for which the 

exemption is not in effect, even if such 

requirements must be complied with 

after the exemption takes effect. 

General Requirements 

§ 62.16220 What requirements must I 

comply with? 

(a) Designated representative 

requirements. The owners and operators 

must have a designated representative, 

and may have an alternate designated 

representative, in accordance with 

§§ 62.16290 through 62.16300. 

(b) Emissions monitoring, reporting, 

and recordkeeping requirements. (1) 

The owners and operators, and the 

designated representative, of each 

facility and each affected EGU at the 

facility must comply with the 

monitoring, reporting, and 

recordkeeping requirements of 

§§ 62.16345, 62.16360, and 62.16365. 

(2) The emissions data determined in 

accordance with §§ 62.16345, 62.16360, 

and 62.16365 must be used to calculate 

allocations of CO2 allowances under 

§ 62.16240(a) and (b) and to determine 

compliance with the CO2 emission 

standard under paragraph (c) of this 

section, provided that, for each 

monitoring location from which mass 

emissions are reported, the mass 

emissions amount used in calculating 

such allocations and determining such 

compliance must be the mass emissions 

amount for the monitoring location 

determined in accordance with 

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§ 62.16345 and rounded to the nearest 

ton. 

(c) CO2 emission standard 

requirements—(1) CO2 emission 

standard. (i) As of the allowance 

transfer deadline for a compliance 

period in a given year, the owners and 

operators of each facility and each 

affected EGU at the facility with affected 

EGUs must hold, in the facility’s 

compliance account, CO2 allowances 

available for deduction for such 

compliance period under § 62.16340(a) 

in an amount not less than the tons of 

total CO2 emissions for such compliance 

period from all affected EGUs at the 

facility. 

(ii) If total CO2 emissions during a 

compliance period in a given year from 

the affected EGUs at a facility are in 

excess of the CO2 emission standard set 

forth in paragraph (c)(1)(i) of this 

section, then: 

(A) The owners and operators of the 

facility and each affected EGU at the 

facility must hold the CO2 allowances 

required for deduction under 

§ 62.16340(d); and 

(B) The owners and operators of the 

facility and each affected EGU at the 

facility are subject to federal 

enforcement pursuant to sections 113(a) 

through (h), and section 304, of the 

Clean Air Act, and the United States, 

States, and other persons have the 

ability to enforce against violations 

(including if an affected EGU does not 

meet its emission standard based on its 

allowances) and secure appropriate 

corrective actions, and must pay any 

fine, penalty, or assessment or comply 

with any other remedy imposed, for the 

same violations, under the Clean Air 

Act, and each ton of such excess 

emissions and each day of such 

compliance period will constitute a 

separate violation of this subpart and 

the Clean Air Act. 

(2) Compliance periods. (i) An 

affected EGU will be subject to the 

requirements under paragraph (c)(1) of 

this section for the compliance period 

starting on January 1, 2022 and for each 

compliance period thereafter. 

(ii) [Reserved] 

(3) Vintage of allowances held for 

compliance. (i) A CO2 allowance held 

for compliance with the requirements 

under paragraph (c)(1)(i) of this section 

for a compliance period must be a CO2

allowance that was allocated for a year 

in such compliance period or for a year 

in a prior compliance period. 

(ii) A CO2 allowance held for 

compliance with the requirements 

under paragraph (c)(1)(ii)(A) of this 

section for a compliance period must be 

a CO2 allowance that was allocated for 

a year in a prior compliance period, or 

the current compliance period, or in the 

immediately following compliance 

period. 

(4) Allowance Tracking and 

Compliance System (ATCS) 

requirements. Each CO2 allowance must 

be held in, deducted from, or transferred 

into, out of, or between ATCS accounts 

in accordance with this subpart. 

(5) Limited authorization. A CO2

allowance is a limited authorization to 

emit one ton of CO2 during the 

compliance period in one year. Such 

authorization is limited in its use and 

duration as follows: 

(i) Such authorization must only be 

used in accordance with the CO2 Massbased Trading Program; and 

(ii) Notwithstanding any other 

provision of this subpart, the 

Administrator has the authority to 

terminate or limit the use and duration 

of such authorization to the extent the 

Administrator determines is necessary 

or appropriate to implement any 

provision of the Clean Air Act. 

(6) Property right. A CO2 allowance 

does not constitute a property right. 

(d) Title V permit requirements. (1) 

Unless otherwise specified in this 

paragraph, all requirements of this 

subpart are applicable requirements that 

must be included in an affected EGU’s 

title V permit. 

(2) The applicable requirements of 

this subpart, as well as other terms or 

conditions necessary to ensure 

compliance with the applicable 

requirements, may be added to, or 

changed in, a title V permit using minor 

permit modification procedures in 

accordance with §§ 70.7(e)(2) and 

71.7(e)(1) of this chapter, provided that 

such changes do not conflict with any 

existing terms of the permit. This 

paragraph explicitly provides that the 

addition of, or change to, an affected 

EGU’s description as described in the 

prior sentence is eligible for minor 

permit modification procedures in 

accordance with §§ 70.7(e)(2)(i)(B) and 

71.7(e)(1)(i)(B) of this chapter. 

(3) No title V permit revision will be 

required for any allocation, holding, 

deduction, or transfer of CO2 allowances 

in accordance with this subpart, 

provided that the requirements 

applicable to such allocations, holdings, 

deductions, or transfers of CO2

allowances are already incorporated in 

such permit. 

(e) Liability. (1) Any provision of the 

CO2 Mass-based Trading Program that 

applies to an affected EGU at a facility 

or the designated representative of 

affected EGUs at a facility will also 

apply to the owners and operators of 

such facility and of the affected EGUs at 

the facility. 

(2) Any provision of the CO2 Massbased Trading Program that applies to 

an affected EGU or the designated 

representative of an affected EGU will 

also apply to the owners and operators 

of such affected EGU. 

(f) Effect on other authorities. No 

provision of the CO2 Mass-based 

Trading Program or exemption under 

§ 62.16215 shall be construed as 

exempting or excluding the owners and 

operators, and the designated 

representative, of an affected EGU from 

compliance with any other provision of 

the applicable, approved state 

implementation plan, a federally 

enforceable permit, or any other 

requirement of the Clean Air Act. 

§ 62.16225 How should I compute time 

under the CO2 Mass-based Trading 

Program? 

(a) Unless otherwise stated, any time 

period scheduled, under the CO2 MassBased Trading Program, to begin on the 

occurrence of an act or event will begin 

on the day the act or event occurs. 

(b) Unless otherwise stated, any time 

period scheduled, under the CO2 MassBased Trading Program, to begin before 

the occurrence of an act or event will be 

computed so that the period ends the 

day before the act or event occurs. 

(c) Unless otherwise stated, if the final 

day of any time period, under the CO2

Mass-Based Trading Program, is not a 

business day, then the time period will 

be extended to the next business day. 

§ 62.16230 What are the administrative 

appeal procedures? 

The administrative appeal procedures 

for decisions of the Administrator under 

the CO2 Mass-Based Trading Program 

are set forth in part 78 of this chapter. 

§ 62.16231 How will the Clean Energy 

Incentive Program be administered under 

the federal plan? 

(a)(1) The Administrator will 

participate in the Clean Energy 

Incentive Program, established under 

subpart UUUU of part 60 of this chapter, 

on behalf of any state for which this 

subpart is promulgated as a federal plan 

under section 111(d) of the Clean Air 

Act. The Administrator will award, on 

behalf of each such state, early action 

allowances for generation and savings 

achieved in 2020 and/or 2021 that result 

from the following types of eligible 

renewable energy (RE) and demand-side 

energy efficiency (EE) projects: 

(i) Metered wind power; 

(ii) Metered solar power; and 

(iii) Demand-side EE implemented in 

a low-income community. 

(2) Eligible RE projects must 

commence construction, and eligible 

demand-side EE projects must 

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commence implementation after 

September 6, 2018 for those states on 

whose behalf the EPA is implementing 

the federal plan. Eligible projects must 

be located in or benefit the state on 

whose behalf the EPA is implementing 

the federal plan. 

(b) Early action allowances will be 

distributed pursuant to a process to be 

prescribed by the Administrator, from 

an allowance set-aside equal to 300 

million allowances for all states. This 

set-aside does not increase the total 

budget of allowances for the affected 

EGUs in the state subject to this subpart. 

(c) The Administrator will match 

these early action allowances with 

additional matching allowances 

pursuant to a process to be prescribed 

by the Administrator. Matching awards 

will be made up to a limit equivalent to 

the state’s pro rata share of 300 million 

short tons of CO2 emissions. 

(d) The awards, including the 

matching award, will be executed as 

follows: 

(1) For RE projects that generate 

metered MWh from wind or solar 

resources: for every two MWh 

generated, the project will receive a 

number of early action allowances the 

Administrator determines to be 

equivalent to one MWh from the setaside under paragraph (b) of this section 

and a number of matching allowances 

the Administrator determines to be 

equivalent to one MWh from the match 

under paragraph (c) of this section. 

(2) For EE projects implemented in 

low-income communities as determined 

by the Administrator solely for purposes 

of this subpart: for every two MWh in 

end-use demand savings achieved, the 

project will receive a number of early 

action allowances the Administrator 

determines to be equivalent to two 

MWh from the set-aside under 

paragraph (b) of this section and a 

number of matching allowances the 

Administrator determines to be 

equivalent to two MWh from the match 

under paragraph (c) of this section. 

Emission Goals, Set-Asides, and 

Allowance Allocations 

§ 62.16235 What are the statewide massbased emission goals, renewable energy 

set-asides, output-based set-asides, and 

Clean Energy Incentive Program early 

action set-asides? 

(a) The statewide mass-based 

emission goals with renewable energy 

set-asides and output-based set-asides 

for allocations of CO2 allowances for the 

interim 3- and 2-year compliance 

periods in 2022 through 2029, and the 

final 2-year compliance periods in 2030 

and thereafter are specified in Table 1 

of this subpart. 

TABLE 1 TO SUBPART MMM OF PART 62—STATEWIDE MASS-BASED EMISSION GOALS 1 (SHORT TONS) 

State 

Interim period Final period 

Step 1 

2022–2024 

Step 2 

2025–2027 

Step 3 

2028–2029 

2030–2031 

and thereafter 

Alabama ........................................... 66,164,470 60,918,973 58,215,989 56,880,474 

Arizona ............................................. 35,189,232 32,371,942 30,906,226 30,170,750 

Arkansas .......................................... 36,032,671 32,953,521 31,253,744 30,322,632 

California .......................................... 53,500,107 50,080,840 48,736,877 48,410,120 

Colorado .......................................... 35,785,322 32,654,483 30,891,824 29,900,397 

Connecticut ...................................... 7,555,787 7,108,466 6,955,080 6,941,523 

Delaware .......................................... 5,348,363 4,963,102 4,784,280 4,711,825 

Florida .............................................. 119,380,477 110,754,683 106,736,177 105,094,704 

Georgia ............................................ 54,257,931 49,855,082 47,534,817 46,346,846 

Idaho ................................................ 1,615,518 1,522,826 1,493,052 1,492,856 

Illinois ............................................... 80,396,108 73,124,936 68,921,937 66,477,157 

Indiana ............................................. 92,010,787 83,700,336 78,901,574 76,113,835 

Iowa ................................................. 30,408,352 27,615,429 25,981,975 25,018,136 

Kansas ............................................. 26,763,719 24,295,773 22,848,095 21,990,826 

Kentucky .......................................... 76,757,356 69,698,851 65,566,898 63,126,121 

Lands of the Fort Mojave Tribe ....... 636,876 600,334 588,596 588,519 

Lands of the Navajo Nation ............. 26,449,393 23,999,556 22,557,749 21,700,587 

Lands of the Uintah and Ouray Reservation ......................................... 2,758,744 2,503,220 2,352,835 2,263,431 

Louisiana .......................................... 42,035,202 38,461,163 36,496,707 35,427,023 

Maine ............................................... 2,251,173 2,119,865 2,076,179 2,073,942 

Maryland .......................................... 17,447,354 15,842,485 14,902,826 14,347,628 

Massachusetts ................................. 13,360,735 12,511,985 12,181,628 12,104,747 

Michigan ........................................... 56,854,256 51,893,556 49,106,884 47,544,064 

Minnesota ........................................ 27,303,150 24,868,570 23,476,788 22,678,368 

Mississippi ........................................ 28,940,675 26,790,683 25,756,215 25,304,337 

Missouri ............................................ 67,312,915 61,158,279 57,570,942 55,462,884 

Montana ........................................... 13,776,601 12,500,563 11,749,574 11,303,107 

Nebraska .......................................... 22,246,365 20,192,820 18,987,285 18,272,739 

Nevada ............................................. 15,076,534 14,072,636 13,652,612 13,523,584 

New Hampshire ............................... 4,461,569 4,162,981 4,037,142 3,997,579 

New Jersey ...................................... 18,241,502 17,107,548 16,681,949 16,599,745 

New Mexico ..................................... 14,789,981 13,514,670 12,805,266 12,412,602 

New York ......................................... 35,493,488 32,932,763 31,741,940 31,257,429 

North Carolina .................................. 60,975,831 55,749,239 52,856,495 51,266,234 

North Dakota .................................... 25,453,173 23,095,610 21,708,108 20,883,232 

Ohio ................................................. 88,512,313 80,704,944 76,280,168 73,769,806 

Oklahoma ......................................... 47,577,611 43,665,021 41,577,379 40,488,199 

Oregon ............................................. 9,097,720 8,477,658 8,209,589 8,118,654 

Pennsylvania .................................... 106,082,757 97,204,723 92,392,088 89,822,308 

Rhode Island .................................... 3,811,632 3,592,937 3,522,686 3,522,225 

South Carolina ................................. 31,025,518 28,336,836 26,834,962 25,998,968 

South Dakota ................................... 4,231,184 3,862,401 3,655,422 3,539,481 

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TABLE 1 TO SUBPART MMM OF PART 62—STATEWIDE MASS-BASED EMISSION GOALS 1 (SHORT TONS)—Continued 

State 

Interim period Final period 

Step 1 

2022–2024 

Step 2 

2025–2027 

Step 3 

2028–2029 

2030–2031 

and thereafter 

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 

1The values in this table are annual amounts; the mass goal for each multi-year compliance period is the annual value multiplied by the number of years in the compliance period. Each emission goal includes the renewable energy set-asides and output-based set-asides (the outputbased set-asides are zero in the first compliance period). The first compliance period goals also include the early action Clean Energy Incentive 

Program set-aside. 

(b) If implementing interstate trading, 

then the Administrator will use the sum 

of a covered group of States’ mass-based 

emission goals as the aggregate massbased emission goal. 

(c) The renewable energy set-aside for 

each State covered by the federal massbased emissions trading plan must 

reserve 5 percent from the State’s 

annual allowances prior to allocation of 

that year’s allowances to facilities. The 

renewable energy set-asides are 

specified in Table 2 of this subpart. 

TABLE 2 TO SUBPART MMM OF PART 62—STATEWIDE RENEWABLE ENERGY SET-ASIDE (SHORT TONS) 

State 

Interim period Final period 

Compliance period 1 

2022–2024 

Compliance period 2 

2025–2027 

Compliance period 3 

2028–2029 

Final compliance periods 

2030–2031 

and thereafter 

Alabama ........................................... 3,308,224 3,045,949 2,910,799 2,844,024 

Arizona ............................................. 1,759,462 1,618,597 1,545,311 1,508,538 

Arkansas .......................................... 1,801,634 1,647,676 1,562,687 1,516,132 

California .......................................... 2,675,005 2,504,042 2,436,844 2,420,506 

Colorado .......................................... 1,789,266 1,632,724 1,544,591 1,495,020 

Connecticut ...................................... 377,789 355,423 347,754 347,076 

Delaware .......................................... 267,418 248,155 239,214 235,591 

Florida .............................................. 5,969,024 5,537,734 5,336,809 5,254,735 

Georgia ............................................ 2,712,897 2,492,754 2,376,741 2,317,342 

Idaho ................................................ 80,776 76,141 74,653 74,643 

Illinois ............................................... 4,019,805 3,656,247 3,446,097 3,323,858 

Indiana ............................................. 4,600,539 4,185,017 3,945,079 3,805,692 

Iowa ................................................. 1,520,418 1,380,771 1,299,099 1,250,907 

Kansas ............................................. 1,338,186 1,214,789 1,142,405 1,099,541 

Kentucky .......................................... 3,837,868 3,484,943 3,278,345 3,156,306 

Lands of the Fort Mojave Tribe ....... 31,844 30,017 29,430 29,426 

Lands of the Navajo Nation ............. 1,322,470 1,199,978 1,127,887 1,085,029 

Lands of the Uintah and Ouray Reservation ......................................... 137,937 125,161 117,642 113,172 

Louisiana .......................................... 2,101,760 1,923,058 1,824,835 1,771,351 

Maine ............................................... 112,559 105,993 103,809 103,697 

Maryland .......................................... 872,368 792,124 745,141 717,381 

Massachusetts ................................. 668,037 625,599 609,081 605,237 

Michigan ........................................... 2,842,713 2,594,678 2,455,344 2,377,203 

Minnesota ........................................ 1,365,158 1,243,429 1,173,839 1,133,918 

Mississippi ........................................ 1,447,034 1,339,534 1,287,811 1,265,217 

Missouri ............................................ 3,365,646 3,057,914 2,878,547 2,773,144 

Montana ........................................... 688,830 625,028 587,479 565,155 

Nebraska .......................................... 1,112,318 1,009,641 949,364 913,637 

Nevada ............................................. 753,827 703,632 682,631 676,179 

New Hampshire ............................... 223,078 208,149 201,857 199,879 

New Jersey ...................................... 912,075 855,377 834,097 829,987 

New Mexico ..................................... 739,499 675,734 640,263 620,630 

New York ......................................... 1,774,674 1,646,638 1,587,097 1,562,871 

North Carolina .................................. 3,048,792 2,787,462 2,642,825 2,563,312 

North Dakota .................................... 1,272,659 1,154,781 1,085,405 1,044,162 

Ohio ................................................. 4,425,616 4,035,247 3,814,008 3,688,490 

Oklahoma ......................................... 2,378,881 2,183,251 2,078,869 2,024,410 

Oregon ............................................. 454,886 423,883 410,479 405,933 

Pennsylvania .................................... 5,304,138 4,860,236 4,619,604 4,491,115 

Rhode Island .................................... 190,582 179,647 176,134 176,111 

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TABLE 2 TO SUBPART MMM OF PART 62—STATEWIDE RENEWABLE ENERGY SET-ASIDE (SHORT TONS)—Continued 

State 

Interim period Final period 

Compliance period 1 

2022–2024 

Compliance period 2 

2025–2027 

Compliance period 3 

2028–2029 

Final compliance periods 

2030–2031 

and thereafter 

South Carolina ................................. 1,551,276 1,416,842 1,341,748 1,299,948 

South Dakota ................................... 211,559 193,120 182,771 176,974 

Tennessee ....................................... 1,705,915 1,553,959 1,467,161 1,417,420 

Texas ............................................... 11,080,665 10,186,403 9,717,567 9,479,442 

Utah ................................................. 1,423,990 1,299,099 1,228,643 1,188,910 

Virginia ............................................. 1,564,510 1,449,550 1,394,924 1,371,656 

Washington ...................................... 619,785 572,057 548,179 536,959 

West Virginia .................................... 3,127,851 2,838,139 2,667,633 2,566,267 

Wisconsin ......................................... 1,675,283 1,528,566 1,445,897 1,399,349 

Wyoming .......................................... 1,926,425 1,748,391 1,643,786 1,581,721 

(d) The output-based set-aside for 

each State under this subpart, beginning 

in compliance period 2, must reserve a 

share of the State’s annual allowances 

prior to allocation of that year’s 

allowances to facilities as set forth in 

this paragraph (d). The output-based setasides are specified in Table 3 of this 

subpart. 

TABLE 3 TO SUBPART MMM OF PART 62—STATEWIDE OUTPUT-BASED SET-ASIDE (SHORT TONS) 

State 

Allowances in output-based 

set-aside 

(short tons) 

Alabama ........................................................................................................................................................... 4,185,496 

Arizona ............................................................................................................................................................. 4,197,813 

Arkansas .......................................................................................................................................................... 2,102,538 

California .......................................................................................................................................................... 8,458,604 

Colorado .......................................................................................................................................................... 1,348,187 

Connecticut ...................................................................................................................................................... 1,090,811 

Delaware .......................................................................................................................................................... 649,190 

Florida .............................................................................................................................................................. 12,102,688 

Georgia ............................................................................................................................................................ 3,563,104 

Idaho ................................................................................................................................................................ 246,638 

Illinois ............................................................................................................................................................... 1,598,615 

Indiana ............................................................................................................................................................. 1,106,150 

Iowa ................................................................................................................................................................. 492,510 

Kansas ............................................................................................................................................................. 62,257 

Kentucky .......................................................................................................................................................... 288,730 

Lands of the Fort Mojave Tribe ....................................................................................................................... 248,127 

Lands of the Navajo Nation ............................................................................................................................. 0 

Lands of the Uintah and Ouray Reservation ................................................................................................... 0 

Louisiana .......................................................................................................................................................... 2,207,879 

Maine ............................................................................................................................................................... 563,925 

Maryland .......................................................................................................................................................... 103,762 

Massachusetts ................................................................................................................................................. 2,439,991 

Michigan ........................................................................................................................................................... 2,105,786 

Minnesota ........................................................................................................................................................ 909,724 

Mississippi ........................................................................................................................................................ 3,132,671 

Missouri ............................................................................................................................................................ 815,210 

Montana ........................................................................................................................................................... 0 

Nebraska .......................................................................................................................................................... 144,635 

Nevada ............................................................................................................................................................. 2,326,529 

New Hampshire ............................................................................................................................................... 542,721 

New Jersey ...................................................................................................................................................... 3,413,100 

New Mexico ..................................................................................................................................................... 627,085 

New York ......................................................................................................................................................... 3,815,381 

North Carolina .................................................................................................................................................. 2,120,178 

North Dakota .................................................................................................................................................... 0 

Ohio ................................................................................................................................................................. 1,757,326 

Oklahoma ......................................................................................................................................................... 3,121,167 

Oregon ............................................................................................................................................................. 1,291,027 

Pennsylvania .................................................................................................................................................... 4,392,931 

Rhode Island .................................................................................................................................................... 778,307 

South Carolina ................................................................................................................................................. 1,029,366 

South Dakota ................................................................................................................................................... 130,831 

Tennessee ....................................................................................................................................................... 632,949 

Texas ............................................................................................................................................................... 15,990,657 

Utah ................................................................................................................................................................. 825,586 

Virginia ............................................................................................................................................................. 3,011,811 

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TABLE 3 TO SUBPART MMM OF PART 62—STATEWIDE OUTPUT-BASED SET-ASIDE (SHORT TONS)—Continued 

State 

Allowances in output-based 

set-aside 

(short tons) 

Washington ...................................................................................................................................................... 1,383,060 

West Virginia .................................................................................................................................................... 0 

Wisconsin ......................................................................................................................................................... 1,181,175 

Wyoming .......................................................................................................................................................... 45,114 

(e)(1) The Clean Energy Investment 

Program Set-Aside for each State 

covered under this subpart must contain 

an amount of allowances shown in 

Table 4 of this subpart, which must 

reserve a share of the State’s annual 

allowances prior to allocation of that 

year’s allowances to facilities as set 

forth in this paragraph. 

TABLE 4 TO SUBPART MMM OF PART 62—CLEAN ENERGY INVESTMENT PROGRAM EARLY ACTION SET-ASIDE (SHORT

TONS) 

State 

Allowances in early action 

set-aside 

(short tons) 

Alabama ........................................................................................................................................................... 3,122,306 

Arizona ............................................................................................................................................................. 1,719,618 

Arkansas .......................................................................................................................................................... 2,187,230 

California .......................................................................................................................................................... 218,846 

Colorado .......................................................................................................................................................... 2,223,192 

Connecticut ...................................................................................................................................................... 69,415 

Delaware .......................................................................................................................................................... 138,392 

Florida .............................................................................................................................................................. 3,230,248 

Georgia ............................................................................................................................................................ 2,755,623 

Idaho ................................................................................................................................................................ 14,929 

Illinois ............................................................................................................................................................... 5,968,721 

Indiana ............................................................................................................................................................. 5,754,076 

Iowa ................................................................................................................................................................. 2,191,183 

Kansas ............................................................................................................................................................. 2,115,630 

Kentucky .......................................................................................................................................................... 4,952,862 

Lands of the Fort Mojave Tribe ....................................................................................................................... 5,885 

Lands of the Navajo Nation ............................................................................................................................. 1,623,066 

Lands of the Uintah and Ouray Reservation ................................................................................................... 175,509 

Louisiana .......................................................................................................................................................... 1,497,428 

Maine ............................................................................................................................................................... 20,739 

Maryland .......................................................................................................................................................... 972,775 

Massachusetts ................................................................................................................................................. 170,471 

Michigan ........................................................................................................................................................... 3,727,861 

Minnesota ........................................................................................................................................................ 2,002,903 

Mississippi ........................................................................................................................................................ 357,307 

Missouri ............................................................................................................................................................ 3,771,322 

Montana ........................................................................................................................................................... 1,310,344 

Nebraska .......................................................................................................................................................... 1,481,695 

Nevada ............................................................................................................................................................. 336,288 

New Hampshire ............................................................................................................................................... 107,798 

New Jersey ...................................................................................................................................................... 446,005 

New Mexico ..................................................................................................................................................... 823,049 

New York ......................................................................................................................................................... 557,771 

North Carolina .................................................................................................................................................. 2,674,590 

North Dakota .................................................................................................................................................... 2,150,635 

Ohio ................................................................................................................................................................. 4,788,372 

Oklahoma ......................................................................................................................................................... 2,067,006 

Oregon ............................................................................................................................................................. 154,353 

Pennsylvania .................................................................................................................................................... 5,039,346 

Rhode Island .................................................................................................................................................... 35,674 

South Carolina ................................................................................................................................................. 1,652,802 

South Dakota ................................................................................................................................................... 264,207 

Tennessee ....................................................................................................................................................... 2,178,084 

Texas ............................................................................................................................................................... 10,400,192 

Utah ................................................................................................................................................................. 1,401,189 

Virginia ............................................................................................................................................................. 1,386,546 

Washington ...................................................................................................................................................... 751,434 

West Virginia .................................................................................................................................................... 3,506,890 

Wisconsin ......................................................................................................................................................... 2,393,870 

Wyoming .......................................................................................................................................................... 3,104,324 

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(2) Allowances may be distributed 

from the set-aside for projects meeting 

the criteria of paragraph (e)(3) of this 

section, upon application of a project 

proponent that meets the requirements 

of § 62.16245(a), except as may be 

prescribed by the Administrator in a 

future action. In order to receive a 

distribution, the project proponent must 

establish a general account in the 

tracking system as provided in 

§ 62.16320(c). 

(3) Projects eligible for distribution of 

allowances from this set-aside must 

meet each of the criteria in paragraphs 

(e)(3)(i) through (iii) of this section. All 

categories of resources other than those 

listed in paragraphs (e)(3)(iii)(A) and (B) 

of this section, and all provisions of this 

subpart relating to such resources, are 

not available or applicable in States 

where this subpart has been 

promulgated as a federal plan pursuant 

to section 111(d)(2) of the Clean Air Act. 

(i) The project was constructed or 

implemented on or after the signature 

date of the final rule promulgating 

subpart UUUU of part 60 of this chapter; 

(ii) The creditable generation or 

energy savings from the project must 

occur in calendar years 2020 or 2021; 

and 

(iii) Generation or energy savings 

must be from one of the following types 

of sources capable of revenue-quality 

metering: 

(A) Onshore wind; 

(B) Solar; or 

(C) Demand-side EE. 

§ 62.16240 When are allowances 

allocated? 

(a) Allowance allocations. (1) By June 

1, 2021, and by June 1 of each year prior 

to the beginning of each compliance 

period thereafter, CO2 allowances will 

be allocated, for the multi-year 

compliance periods in the Interim 

Period beginning in 2022 and the Final 

Period beginning in 2030, as provided 

by the Administrator in a notice of data 

availability or through this subpart (if 

applicable). Providing an allocation to 

an entity does not constitute as an 

applicability determination of an 

affected EGU. 

(2) Notwithstanding paragraph (a)(1) 

of this section, if an affected EGU which 

is provided an allocation does not 

operate for 2 consecutive calendar years, 

then such affected EGU will not be 

allocated the CO2 allowances provided 

by the Administrator in a notice of data 

availability or through this subpart (if 

applicable) for the affected EGU for the 

next compliance period for which 

allowances have not yet been recorded 

and for each compliance period after 

that compliance period. All CO2

allowances that would otherwise have 

been allocated to such affected EGU will 

be allocated to the renewable energy setaside for the State where such affected 

EGU is located and for the respective 

compliance periods involved. 

(3) Notwithstanding paragraph (a)(1) 

of this section, if an affected EGU 

provided an allocation issued by the 

Administrator in notice of data 

availability or through this subpart (if 

applicable) is modified or reconstructed 

such that it is no longer subject to this 

subpart, then such affected EGU will not 

be allocated the CO2 allowances 

provided for the affected EGU for the 

next compliance period for which 

allowances have not yet been recorded 

and for each compliance period after 

that compliance period. All CO2

allowances that would otherwise have 

been allocated to such affected EGU will 

be allocated to the renewable energy setaside for the State where such affected 

EGU is located and for the respective 

compliance periods involved. 

(b) Set-asides—(1) Renewable energy 

set-asides. (i) By December 1, 2021 and 

December 1 of each year thereafter, the 

Administrator will calculate and 

allocate the CO2 allowance allocation to 

each approved renewal energy project in 

a State, in accordance with 

§ 62.16245(a)(2) through (5), for the 

generation year of the applicable 

calculation deadline under this 

paragraph. 

(ii) By December 1, 2021 and 

December 1 of each year thereafter, the 

Administrator will calculate and 

allocate the CO2 allowance allocation to 

each affected EGU in a State, in 

accordance with § 62.16245(a)(6) and (7) 

for the generation year of the applicable 

calculation, and will promulgate a 

notice of data availability of the results 

of the calculations. 

(2) Output-based set-asides. (i) By 

November 1 of the first year of each 

compliance period beginning in 2025, 

and each compliance period thereafter, 

the Administrator will calculate and 

allocate the CO2 allowance allocation to 

each affected EGU in a State, in 

accordance with § 62.16245(b)(3), for 

the generation period of the applicable 

calculation deadline under this 

paragraph. 

(ii) By November 1 of the first year of 

each compliance period beginning in 

2025, and each compliance period 

thereafter, the Administrator will 

calculate and allocate the CO2

allowance allocation to each affected 

EGU in a State, in accordance with 

§ 62.16245(b)(4) and (5) for the 

generation period of the applicable 

calculation, and will promulgate a 

notice of data availability of the results 

of the calculations. 

(c) Affected EGUs incorrectly 

allocated CO2 allowances. (1) For each 

compliance period in 2022 and 

thereafter, if the Administrator 

determines that CO2 allowances were 

allocated under paragraph (a) of this 

section, or under a provision of a state 

allowance distribution methodology 

approved under subpart UUUU of part 

60 of this chapter, where such 

compliance period and the recipient are 

covered by the provisions of paragraph 

(c)(1)(i) of this section or were allocated 

under § 62.16245(a) and (b), where such 

compliance period and the recipient are 

covered by the provisions of paragraph 

(c)(1)(ii) of this section, then the 

Administrator will notify the designated 

representative of the recipient and will 

act in accordance with the procedures 

set forth in paragraphs (c)(2) through (5) 

of this section. The situations for the 

Administrator to act according to the 

procedures in paragraphs (c)(2) through 

(5) are if: 

(i)(A) The recipient is not actually an 

affected EGU under § 62.16210 as of 

January 1, 2022 and is allocated CO2

allowances for such compliance period 

or, in the case of an allocation under a 

provision of a state allowance 

distribution methodology approved 

under subpart UUUU of part 60 of this 

chapter, the recipient is not actually an 

affected EGU as of January 1, 2022 and 

is allocated CO2 allowances for such 

compliance period that the state 

allowance distribution methodology 

provides should be allocated only to 

recipients that are affected EGUs as of 

January 1, 2022; or 

(B) The recipient is not located as of 

January 1 of the compliance period in 

the State from whose CO2 allowances 

the CO2 allowances allocated under 

paragraph (a) of this section, or under a 

provision of a state allowance 

distribution methodology approved 

under subpart UUUU of part 60 of this 

chapter, were allocated for such 

compliance period. 

(ii) The recipient is not actually an 

affected EGU under § 62.16210 as of 

January 1 of such compliance period 

and is allocated CO2 allowances for 

such compliance period or, in the case 

of an allocation under a provision of a 

state allowance distribution 

methodology approved under subpart 

UUUU of part 60 of this chapter, the 

recipient is not actually an affected EGU 

as of January 1 of such compliance 

period and is allocated CO2 allowances 

for such compliance period that the 

state allowance distribution 

methodology provides should be 

allocated only to recipients that are 

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affected EGUs as of January 1 of such 

compliance period. 

(2) Except as provided in paragraph 

(c)(3) or (4) of this section, the 

Administrator will not record such CO2

allowances under § 62.16325. 

(3) If the Administrator already 

recorded such CO2 allowances under 

§ 62.16325 and if the Administrator 

makes the determination under 

paragraph (c)(1) of this section before 

making deductions for the facility that 

includes such recipient under 

§ 62.16340(b) for such compliance 

period, then the Administrator will 

deduct from the account in which such 

CO2 allowances were recorded an 

amount of CO2 allowances allocated for 

the same or a prior compliance period 

equal to the amount of such alreadyrecorded CO2 allowances. The 

authorized account representative must 

ensure that there are sufficient CO2

allowances in such account for 

completion of the deduction. 

(4) If the Administrator already 

recorded such CO2 allowances under 

§ 62.16325 and if the Administrator 

makes the determination under 

paragraph (c)(1) of this section after 

making deductions for the facility that 

includes such recipient under 

§ 62.16340(b) for such compliance 

period, then the Administrator will not 

make any deduction to take account of 

such already-recorded CO2 allowances. 

(5)(i) With regard to the CO2

allowances that are not recorded, or that 

are deducted as an incorrect allocation, 

in accordance with paragraphs (c)(2) 

and (3) of this section for a recipient 

under paragraph (c)(1)(i) of this section, 

the Administrator will: 

(A) Transfer such CO2 allowances to 

the renewable energy set-aside for such 

compliance period for the State from 

whose CO2 allowances the CO2

allowances were allocated; or 

(B) If the State has a state allowance 

distribution methodology approved 

under subpart UUUU of part 60 of this 

chapter covering such compliance 

period, then include such CO2

allowances in the portion of the CO2

allowances that may be allocated for 

such compliance period in accordance 

with such state allowance distribution 

methodology. 

(ii) With regard to the CO2 allowances 

that were not allocated from a 

renewable energy or output-based setaside for such compliance period and 

that are not recorded, or that are 

deducted as an incorrect allocation, in 

accordance with paragraphs (c)(2) and 

(3) of this section for a recipient under 

paragraph (c)(1)(ii) of this section, the 

Administrator will: 

(A) Transfer such CO2 allowances to 

the renewable energy set-aside for such 

compliance period; or 

(B) If the State has a state allowance 

distribution methodology approved 

under subpart UUUU of part 60 of this 

chapter covering such compliance 

period, then include such CO2

allowances in the portion of the CO2

allowances that may be allocated for 

such compliance period in accordance 

with such state allowance distribution 

methodology. 

(iii) With regard to the CO2

allowances that were allocated from the 

renewable energy or output-based setaside for such compliance period and 

that are not recorded, or that are 

deducted as an incorrect allocation, in 

accordance with paragraphs (c)(2) and 

(3) of this section for a recipient under 

paragraph (c)(1)(ii) of this section, the 

Administrator will transfer such CO2

allowances back to the renewable 

energy set-aside, or to the output-based 

set-aside, respectively, for such 

compliance period. 

§ 62.16245 How are set-aside allowances 

allocated? 

(a)(1) Renewable energy set-aside. The 

Administrator will establish a 

renewable energy set-aside as set forth 

in § 62.16235(c), and allocate CO2

allowances from the set-aside for each 

year of a compliance period as outlined 

in this section. 

(2) Eligible renewable energy capacity. 

To be eligible to receive renewable 

energy set-aside allowances, an eligible 

resource must meet each of the 

requirements in paragraphs (a)(2)(i) 

through (v) of this section. Any resource 

that does not meet the requirements of 

paragraphs (a)(2)(i) through (v) of this 

section cannot receive set-aside 

allowances. 

(i) The resource must be a renewable 

energy resource that falls into one of the 

following categories of resources: onshore utility scale wind, solar, 

geothermal power, or utility scale 

hydropower. 

(ii) The resources must only include 

resources which increased new installed 

electrical generation nameplate 

capacity, or new electrical savings 

measures installed or implemented after 

January 1, 2013. If a resource had a 

nameplate capacity uprate, then setaside allowances may be issued only for 

the difference in generation between the 

uprated nameplate capacity and its 

nameplate capacity prior to the uprate. 

Set-aside allowances must not be issued 

for generation for an uprate that 

followed a derate that occurred on or 

after January 1, 2013. A resource that is 

relicensed or receives a license 

extension is considered existing 

capacity and is not an eligible resource, 

unless it receives a capacity uprate as a 

result of the relicensing process that is 

reflected in its relicensed permit. In 

such a case, only the difference in 

nameplate capacity between its 

relicensed permit and its prior permit is 

eligible to be issued set-aside 

allowances. 

(iii) The resource must be located in 

the mass-based State for which the setaside has been designated. 

(iv) The resource must be connected 

to, and delivers energy to or saves 

electricity, on the electric grid in the 

contiguous United States. 

(v) The resource must not have 

received emission rate credits (ERCs) for 

any period of time for which it receives 

set-aside allowances. 

(3) Process for issuance of set-aside 

allowances. The process and 

requirements for issuance of set-aside 

allowances are set forth in paragraphs 

(a)(3)(i) through (x) of this section. 

(i) Eligibility application. To receive 

set-aside allowances, an authorized 

account representative of an eligible 

resource must submit an eligibility 

application to the Administrator that 

demonstrates that the requirements of 

paragraph (a)(2) of this section are met 

and demonstrates that the following 

requirements are met: 

(A) Identification of the authorized 

account representative of the eligible 

resource, including the authorized 

account representative’s name, address, 

email address, telephone number, and 

allowance tracking system account 

number; and 

(B) Identification of the eligible 

resource(s), including the physical 

location of the eligible resource; contact 

information for the owner or operator of 

the eligible resource, if different from 

the authorized account representative 

and designated representative; generator 

prime mover and technology type; 

generator nameplate capacity (if 

applicable); generator category (e.g., 

wholesale generator, wholesale 

generator also serving onsite customer 

load, customer-sited distributed 

generator) (if applicable); facility and 

generating unit IDs (EIA ORIS Code, 

Facility Registration System (FRS) Code, 

if applicable) (if applicable); the control 

area, balancing authority, ISO 

conditions as defined in § 62.16375 (if 

applicable), or regional transmission 

organization in which the generator is 

located (if applicable); and a copy of the 

most recent filing of a copy of the 

generating facility’s U.S. Energy 

Information Agency’s Annual Electric 

Generator Report Form EIA–860 (if 

applicable). 

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(ii) Renewable energy providers must 

open a general account per the 

requirements in § 62.16320(c), and 

submit a project application for 

renewable energy set-aside allowances 

to the Administrator by June 1 of the 

year prior to the generation year for 

which set-aside allowances are 

requested. Providers may update 

submitted projections for future 

generation years, these projections must 

be received by June 1 of the year prior 

to the generation year in question. The 

project application must contain the 

following information: 

(A) Projection of the project’s annual 

renewable energy generation in MWh. 

(B) Documentation of the 

methodology, data facilities, and 

assumptions used to project the 

project’s annual renewable energy 

generation. 

(C) A certification that the eligibility 

application has only been submitted to 

the Administrator or pursuant to an 

EPA-approved multi-State approach 

where States are providing for joint 

issuance of allowances pursuant to the 

authority in their individual State plans. 

(D) A evaluation, measurement, and 

verification (EM&V) plan. 

(E) A verification report from an 

accredited independent verifier who 

meets the requirements of § 62.16275 

and § 62.16280. While considered a part 

of the eligibility application, the 

verification report must be submitted 

separately by the accredited 

independent verifier to the 

Administrator. 

(F) An authorization that provides for 

the following: the Administrator may 

inspect (including a physical inspection 

of the eligible resource and its meter) 

and/or audit the eligible resource at any 

time and verify that the eligible resource 

and the EM&V plan have been 

implemented as described in the 

eligibility application. 

(G) The following statement, signed 

by the authorized account 

representative of the eligible resource: 

(1) ‘‘I certify under penalty of law that 

I have personally examined, and am 

familiar with, the statements and 

information submitted in this document 

and all its attachments. Based on my 

personal knowledge and/or inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(2) [Reserved] 

(H) Any other information required by 

the Administrator. 

(4) Monitoring and verification. After 

the generation year for which a provider 

received set-aside allowances for an 

eligible resource, the authorized account 

representative must submit to the 

Administrator: 

(i) A measurement and verification 

(M&V) report. 

(ii) A verification report from an 

accredited independent verifier that 

meets the requirements of § 62.16275 

and § 62.16280. While considered a part 

of the M&V report, the verification 

report must be submitted separately by 

the accredited independent verifier to 

the Administrator. 

(5) Allocation of renewable energy setaside allowances. The Administrator 

will enter the projected generation from 

each approved project into a pool of 

projects for that State that will receive 

set-asides for a generation year. 

(i) The Administrator will distribute 

renewable energy set-aside allowances 

for a generation year with the number of 

allowances distributed to each project 

prorated according to its percentage of 

the total approved projected MWhs for 

that State that the project represents. 

(ii) If in the previous generation year, 

the project did not reach the MWhs 

projected, then the unfulfilled MWhs 

will be subtracted from that provider’s 

projected generation eligible for the setaside pool. 

(iii) If the unfulfilled MWhs from a 

previous year exceed the projected 

hours for the generation year, then the 

Administrator will carry over the deficit 

and subtract from the projected 

generation in subsequent years until 

there is no deficit. If this deficit is 

greater than 10 percent in a particular 

year, then the provider will need to 

provide an explanation to the 

Administrator of the deficit, and will be 

required to reevaluate their projections 

for future years. If such deficits continue 

through all 3 years of the first or second 

compliance period, then the 

Administrator will disqualify the 

provider from receiving future set-asides 

for the following compliance period. 

(6) Surplus renewable set-aside 

allowances. If, after completion of the 

procedures under paragraph (a)(5) of 

this section for each compliance period, 

any unallocated CO2 allowances remain 

in the renewable energy set-aside for the 

State for such generation year, the 

Administrator will allocate the amount 

of CO2 allowances in a pro rata fashion 

on the same distribution basis as their 

initial allocations were made to each 

affected EGU that: is in the State; is 

allocated an amount of CO2 allowances 

in the notice of data availability issued 

under § 62.16240(a)(1); and continues to 

be allocated CO2 allowances for such 

compliance period in accordance with 

§ 62.16240(a)(2). 

(7) Notice of surplus renewable energy 

set-aside allowance distribution. The 

Administrator will make public the 

amount of CO2 allowances allocated 

under paragraph (a)(6) of this section for 

such generation year period to each 

affected EGU eligible for such 

allocation. 

(b)(1) Output-based set-aside. The 

Administrator will establish an outputbased set-aside beginning in compliance 

period 2, and allocate CO2 allowances 

from the set-aside for each year of a 

compliance period as set forth in 

§ 62.16235(c). 

(2) Unit eligibility. To be eligible to 

receive output-based set-aside 

allowances, affected EGUs must meet 

the following eligibility requirements: 

(i) The affected EGU must be a natural 

gas combined cycle unit; 

(ii) The affected EGU must be located 

in the mass-based State for which the 

set-aside has been designated; and 

(iii) The affected EGU’s average 

capacity factor in the preceding 

compliance period was above 50 

percent based on net summer capacity 

and net generation. 

(3) Allocation of output-based setaside allowances. The Administrator 

will allocate output based set-aside 

allowances for each eligible EGU based 

on its average net generation and net 

summer capacity in the preceding 

compliance period. 

(i) The Administrator will calculate 

the amount of allowances an eligible 

EGU receives from the output-based setaside as the unit’s average net 

generation in the preceding compliance 

period over 50 percent multiplied by the 

allocation rate of 1,030 lb/MWh-net. 

(ii) If the amount of total allowances 

exceeds the size of the State’s set-aside, 

then the allowances will be allocated to 

the State’s eligible generation on a prorata basis. 

(iii) The Administrator will provide 

notice of the net summer capacity and 

net generation data used, and the 

resulting allocations by August 1 of the 

first year of each compliance period 

beginning in 2025. The notice of the net 

summer capacity and net generation 

data used, and the resulting allocations, 

must allow 30 days for public comment 

on the data and allocations, until 

August 31 of the same year. 

(iv) The Administrator will provide 

notice of the final set-aside allocations 

by November 1 of the same year. 

(4) Surplus output-based set-aside 

allowances. If, after completion of the 

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procedures under paragraph (b)(3) of 

this section for each compliance period, 

any unallocated CO2 allowances remain 

in the out-put based set-aside for the 

State for such generation period, the 

Administrator will allocate the amount 

of CO2 allowances in a pro rata fashion 

on the same distribution basis as their 

initial allocations were made to each 

affected EGU that: is in the State; is 

allocated an amount of CO2 allowances 

in the notice of data availability issued 

under § 62.16240(a)(1); and continues to 

be allocated CO2 allowances for such 

compliance period in accordance with 

§ 62.16240(a)(2). 

(5) Notice of surplus output-based setaside. The Administrator will notify the 

public, through the promulgation of the 

notices of data availability described in 

§ 62.16240(b)(1) and (2), of the amount 

of CO2 allowances allocated under 

paragraphs (b)(3) and (4) of this section 

for such compliance period to each 

affected EGU eligible for such 

allocation. 

§ 62.16250 What is the process for 

revocation of qualification status of an 

eligible resource? 

(a) If an eligible resource is found to 

not meet the requirements of § 62.16260 

in the CO2 Mass-based Trading Program, 

then the Administrator will revoke the 

eligibility of the eligible resource to be 

issued set-aside allowances. In addition, 

the provisions of § 62.16255(d) may 

apply. 

(b) Any instance of intentional 

misrepresentation in an eligibility 

application or M&V report may be cause 

for revocation of the qualification status 

of an eligible resource. 

(c) Repeated instances of error or 

misstatement of MWh of electricity 

generation or savings in submitted M&V 

reports, or in any other submissions 

may be cause for the Administrator to 

revoke the eligibility of an eligible 

resource to be issued set-aside 

allowances. 

(d) In the event of an intentional 

misrepresentation, or repeated instances 

of error or misstatement, in program 

submissions, by the authorized account 

representative of the eligible resource, 

the Administrator may prohibit the 

eligible resource from any further 

eligibility to be issued allowances. In 

addition, the provisions of § 62.16255(a) 

through (d) may apply. 

§ 62.16255 What is the process for error 

adjustments or misstatement, and 

suspension of allowance issuance? 

(a) In the event of error or 

misstatement of quantified MWh of 

electricity generation or savings in a 

previous M&V report for which set-aside 

allowances have been issued, the 

Administrator may adjust the number of 

set-aside allowances issued in a 

subsequent reporting period to address 

the error or misstatement, by subtracting 

a number of MWh from the quantified 

and verified MWh in the M&V report for 

the subsequent reporting period. In the 

event that an error or inadvertent 

misstatement occurs in a final M&V 

report for an eligible resource, for which 

set-aside allowances have been issued, 

the provisions of paragraph (b) of this 

section will apply. 

(b) In the event of error or 

misstatement of quantified MWh of 

electricity generation or savings in the 

final M&V report for an eligible 

resource, for which set-aside allowances 

have been issued, the Administrator 

will revoke set-aside allowances from 

the general account held by the 

authorized account representative of the 

eligible resource, in an amount 

necessary to correct the error or 

misstatement. In the event that the 

general account of the eligible resource 

holds an insufficient number of setaside allowances to correct the error or 

misstatement, the authorized account 

representative must submit to the 

Administrator within 30 days a number 

of set-aside allowances necessary to 

correct the error or misstatement. 

Failure to meet this requirement will 

result in prohibition of the authorized 

account representative for the eligible 

resource from further participation in 

the program, unless reauthorized at the 

discretion of the Administrator. 

(c) The Administrator may freeze the 

general account held by an authorized 

account representative of an eligible 

resource at any time, for cause, if the 

Administrator determines set-aside 

allowances have been improperly 

issued, based on a misrepresentation or 

misstatement in an eligibility 

application or M&V report. The 

Administrator may also freeze the 

general account of an authorized 

account representative of an eligible 

resource pending investigation of 

potential misrepresentation, error, or 

misstatement in an eligibility 

application of an eligible resource, or in 

an M&V report for which set-aside 

allowances have been issued. Freezing a 

general account will prevent transfer of 

allowances out of the account. 

(d) If set-aside allowances are issued 

for an eligible resource that is found to 

be ineligible, then the Administrator 

may take the actions in paragraphs 

(d)(1) through (3) of this section. 

(1) Freeze the general account of the 

authorized account representative for an 

eligible resource, preventing any 

transfers of allowances out of the 

account. 

(2) Revoke or deduct allowances held 

in the general account of the authorized 

account representative for an eligible 

resource, in a number equal to the 

number of allowances issued for the 

ineligible eligible resource. 

(3) In the event that the general 

account of the eligible resource holds a 

number of allowances less than the 

number of set-aside allowances issued 

for the ineligible eligible resource, the 

delegated representative of an eligible 

resource must submit to the 

Administrator within 30 days a number 

of allowances necessary to fully account 

for all allowances issued for the 

ineligible eligible resource. Failure to 

meet this requirement will result in 

prohibition of the eligible resource from 

further participation in the program, 

unless reauthorized at the discretion of 

the Administrator. 

(e) The Administrator may 

temporarily or permanently suspend 

issuance of set-aside allowances for an 

eligible resource, for the following 

reasons in paragraphs (e)(1) through (3) 

of this section. 

(1) Pending investigation of potential 

misrepresentation, error, or 

misstatement in an M&V report, for 

which set-aside allowances have been 

issued, or the eligibility status of an 

eligible resource. 

(2) In the case of repeated error or 

misstatements in submitted M&V 

reports. 

(3) In the case of an intentional 

misrepresentation in a submitted M&V 

report. 

Evaluation Measurement and 

Verification Plans, Monitoring and 

Verification Reports, and Verification 

§ 62.16260 What are the requirements for 

evaluation, measurement and verification 

plans for eligible resources? 

(a) EM&V plan requirements. Any 

EM&V plan submitted in support of the 

issuance of a set-aside allowance 

pursuant to this rule must meet the 

requirements of this section. 

(b) General EM&V plan criteria. Each 

EM&V plan must identify the eligible 

resource and its approved eligibility 

application. 

(c) Specific EM&V plan criteria. Each 

EM&V plan must provide the manner in 

which the electricity generated or saved 

by the eligible resource will be 

quantified, monitored and verified, and 

the manner of quantification, 

monitoring and verification must meet 

the criteria listed in paragraphs (c)(1) 

through (7) of this section, as applicable 

to the specific eligible resource. 

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(1) For a nuclear energy resource or a 

renewable energy resource with a 

nameplate capacity of 10 kW or more 

and for a renewable energy resource 

with a nameplate capacity of less than 

10 kW for which metered data are 

available, each EM&V plan must specify 

that the requirements in paragraphs 

(c)(1)(i) through (vi) of this section must 

be met. 

(i) The generation data are physically 

measured on a continuous basis using a 

revenue-quality meter, which means a 

meter used by a control area operator for 

financial settlements, or a meter that 

meets the American National Standards 

Institute No. C12.20., Code for 

Electricity Metering, metering accuracy 

standards, or a meter that meets an 

alternative equivalent standard that has 

been approved in advance of its use to 

measure generation pursuant to this 

regulation by the EPA. 

(ii) The generating data are measured 

at the generator’s bus bar, or, for a 

renewable energy resource with a 

nameplate capacity of less than 10 kW 

that is interconnected behind an 

individual business or household meter, 

the generating data were measured at 

the AC output of the inverter and 

adjusted to reflect the only energy 

delivered into either the transmission or 

distribution grid at the generator bus bar 

and not any energy used on-site at the 

generator. 

(iii) The generation data from only 

one eligible resource generating unit 

may be associated with each meter, and 

generation data may not be aggregated, 

unless all the following provisions are 

met: 

(A) All of the generating units have 

the same essential generation 

characteristics; 

(B) All of the generating units are 

located in the same State; 

(C) The nameplate capacity of the 

individual units being aggregated is 

each less than 150 kW, and units 

collectively do not exceed a total 

nameplate capacity of 1 MW when 

aggregated, or alternative requirements 

approved by the EPA in connection 

with the specific State plan pursuant to 

which that EM&V plan or M&V report 

is submitted; and 

(D) The generation data are measured 

by the same type of meter that is subject 

to the same maintenance and quality 

assurance procedures. 

(iv) The generation data are collected 

electronically and telemetered from the 

generator to its control area operator and 

verified through a control area energy 

accounting or settlement process which 

occurs at least monthly, unless the 

generation unit does not go through a 

control area operator, in which case the 

generation data must be collected by 

manual meter readings conducted by an 

independent verifier that is either not 

affiliated with the owner or operator of 

the qualifying renewable energy 

generating resource or is precluded 

pursuant to the relevant State plan from 

the ability to transfer or retire set-aside 

allowances issued to that qualifying 

renewable energy generating resource 

or, if the generating unit is less than 10 

kw and does not generate enough 

electricity to enable monthly reporting, 

then the data may be self-reported and 

reported no less than annually. 

(v) The generation data serve a load 

that otherwise would have been served 

by the grid if not for the generator. 

Specifically: 

(A) Set-aside allowances shall not be 

issued for energy generation used to 

supply the ancillary equipment used to 

operate a generating station or 

substation (‘‘station service’’) or 

parasitic load on the generator’s side of 

the point of interconnection; and 

(B) For generators interconnected to 

transmission systems and with on-site 

loads other than station service drawing 

generation before the metering point, 

set-aside allowances may be issued for 

on-site load, if the owner or operator of 

the eligible resource can demonstrate 

that the metering used is capable of 

distinguishing between on-site load and 

station service. 

(vi) Any other requirements approved 

by the EPA in connection with the 

specific State plan pursuant to which 

that EM&V plan is submitted. 

(2) For a renewable energy resource 

with a nameplate capacity of less than 

10 kW and that does not have a meter, 

each EM&V plan must require that the 

following requirements in paragraphs 

(c)(2)(i) through (vii) of this section are 

met. 

(i) Metered data are unavailable. 

(ii) At least 1 MW of net energy 

output is generated to the distribution or 

transmission system over a continuous 

365-day period. 

(iii) The generation data may not be 

aggregated, unless the following 

provisions are met: 

(A) All of the generating units have 

the same essential generation 

characteristics; 

(B) All of the generating units are 

located in the same State; 

(C) The nameplate capacity of the 

individual units being aggregated is 

each less than 150 kW, and units 

collectively do not exceed a total 

nameplate capacity of 1 MW when 

aggregated, or alternative requirements 

approved by the EPA in connection 

with the specific State plan pursuant to 

which that EM&V plan or M&V report 

is submitted; and 

(D) The generation data are measured 

by the same generation estimating 

software or algorithms. 

(iv) The generation data are measured 

on at least a monthly basis using 

generation estimating software or 

algorithms that are based on an on-site 

inspection prior to interconnection and 

a resource study (wind, shading, solar 

irradiance, depending on the resource), 

or engineering information that takes 

into account the capacity, age, and type 

of qualifying energy generating resource, 

and all input parameters and 

assumptions must be clearly delineated, 

or if the generating unit does not 

generate enough electricity to enable 

monthly reporting, then the data may be 

reported no less than annually. 

(v) The generation data are selfreported to the distribution utility 

through an electronic internet-based 

portal with software that reports total 

and hourly generation. 

(vi) The generation data serves a load 

that otherwise would have been served 

by the grid if not for the generator. The 

set-aside allowance is only based on 

generation transferred from the eligible 

resource to the transmission or 

distribution grid, and is not based on 

the generation used on-site by the 

customer. 

(vii) Any other requirements 

approved by the EPA in connection 

with the specific State plan pursuant to 

which that EM&V plan is submitted. 

(3) For qualified biomass feedstocks 

used, in addition to the requirements of 

paragraph (c)(1) or (2) of this section, 

whichever section is applicable, each 

EM&V plan must demonstrate that the 

requirements approved by the EPA for 

that biomass feedstock, and its 

associated biogenic CO2, have been met. 

(4) For a waste-to-energy resource, in 

addition to the requirements of 

paragraph (c)(1) or (2) of this section, as 

applicable, and paragraph (c)(3) of this 

section, each EM&V plan must specify: 

(i) The total net energy generation 

from the resource in MWh; 

(ii) The method for determining the 

specific portion of the total net energy 

output from the resource that is related 

to the biogenic portion of the waste; and 

(iii) The net energy output is 

measured with the relevant method 

approved by the EPA in connection 

with the specific State plan pursuant to 

which that EM&V plan is submitted 

demonstrates that the requirements 

approved by the EPA in connection 

with that State plan have been met. 

(5) For a combined heat and power 

unit, in addition to the requirements of 

paragraphs (c)(1) or (2) of this section, 

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as applicable, and paragraph (c)(3) of 

this section, each EM&V plan must meet 

one of the requirements in paragraphs 

(c)(5)(i) through (iv) of this section, as 

applicable, and any other requirements 

approved by the EPA. 

(i) If the combined heat and power 

unit has an electric generating capacity 

greater than 25 MW, then the EM&V 

plan must meet the requirements that 

apply to an affected EGU under 

§ 62.16540 of this subpart. 

(ii) If the combined heat and power 

unit has an electric generating capacity 

less than or equal to 25 MW and greater 

than 1 MW, and it uses only natural gas 

and/or distillate fuel oil, then the EM&V 

plan must meet the low mass emission 

unit CO2 emission monitoring and 

reporting methodology in part 75 of this 

chapter. 

(iii) If the combined heat and power 

unit has an electric generating capacity 

less than or equal to 25 MW and greater 

than 1 MW, and it uses anything other 

than only natural gas and/or distillate 

fuel oil, then the EM&V plan must meet 

the low mass emission unit CO2

emission monitoring and reporting 

methodology in part 75 of this chapter. 

(iv) If the combined heat and power 

unit has an electric generating capacity 

less than or equal to 1 MW the unit 

must keep monthly cumulative 

recordings of useful thermal output and 

fossil fuel input along with the 

determination of baseline thermal 

source efficiencies based on 

manufacturer data. For CHP units that 

directly serve on-site end-use electricity 

loads, avoided transmission and 

distribution (T&D) system losses can be 

assessed as is commonly practiced with 

demand-side EE. 

(6) For electricity savings that avoid a 

transmission and distribution loss, each 

EM&V plan must measure the 

transmission and distribution loss based 

on the lesser of 6 percent of the sitelevel 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. No other transmission and 

distribution loss factors may be used in 

calculating the electricity savings, 

including measures such as 

conservation voltage reduction and volt/ 

VAR optimization. 

(7) Each EM&V plan for an EE 

program, EE project, or EE measure 

must specify how each of the 

requirements in paragraphs (c)(7)(i) 

through (x) of this section will be met 

in quantifying the electricity savings 

from that EE program, EE project, or EE 

measure. 

(i) All electricity savings must be 

quantified on an ex-post basis, which 

means after the electricity savings have 

occurred, or on a real-time basis, which 

means at the time the electricity savings 

are occurring. Electricity savings must 

not be quantified on an ex-ante basis, 

which means estimates of MWh savings 

that are generated prior to implementing 

the subject EE program, EE project, or 

EE measure, and that are not quantified 

using EM&V methods and procedures. 

(ii) All electricity savings must be 

quantified and verified based on 

methods and procedures detailed in an 

industry best-practice EM&V protocol or 

guideline. Each EM&V plan must 

include a demonstration of how the 

best-practice protocol or guideline was 

selected and will be applied to the 

specific EE program, EE project, or EE 

measure covered in the EM&V plan, and 

an explanation of why that particular 

protocol or guideline was selected. 

Protocols and guidelines are considered 

to be best practice if they: 

(A) Have gone through a rigorous and 

credible peer review process that shows 

the applicable methods to be valid 

through empirical testing; and 

(B) Have been accepted and approved 

for use by identifiable state regulatory 

commissions. Examples of such 

protocols and guidelines that may be 

provided in EM&V guidance issued by 

the Administrator will be acceptable. 

(iii) All electricity savings must be 

quantified as the difference between the 

observed electricity use and a common 

practice baseline (CPB), which is the 

equipment that would typically have 

been 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. 

Examples of CPBs for specific EE 

programs, EE projects, EE measures, and 

for certain EM&V methods that may be 

provided in EM&V guidance issued by 

the Administrator will be acceptable. 

The EM&V plan must specify the reason 

the specific CPB was selected, which 

must include an analysis of the 

appropriateness of that CPB for the EE 

program, EE project, or EE measure 

covered in the EM&V plan, based on: 

(A) Characteristics of the EE program, 

EE project, or EE measure; 

(B) The delivery mechanism used to 

implement the EE program, EE project, 

or EE measure (e.g., installed as part of 

a utility EE program versus a point-ofsale rebate); 

(C) Local consumer and market 

characteristics; 

(D) Applicable building energy codes 

and standards and average compliance 

rates; and 

(E) The method applied: project-based 

measurement and verification (PB–MV), 

comparison group approaches, or 

deemed savings. 

(iv) All electricity savings must be 

quantified by applying one or more of 

the following methods: PB–MV, 

comparison group approaches, or 

deemed savings. 

(A) If a comparison group approach is 

used, then the EM&V plan must 

quantify electricity savings by taking the 

difference between a comparison 

group’s electricity use and the 

electricity use of EE program 

participants. Comparison group 

approaches may include randomized 

control trials and quasi-experimental 

methods, as described in industry bestpractice protocols and guidelines. 

Examples of such protocols and 

guidelines provided in EM&V guidance 

that may be issued by the Administrator 

will be acceptable. 

(B) If deemed savings are used, then 

the EM&V plan must specify that the 

deemed savings values will only be 

used for the specific EE measure for 

which they were derived. The EM&V 

plan must also specify the name and 

Web address of the technical reference 

manual (TRM) in which all deemed 

electricity savings values will be 

documented. Prior to use in an EM&V 

plan, all TRMs must undergo a review 

process in which the public, 

stakeholders, and experts are invited— 

with adequate advance notification (via 

the internet and other social media)—to 

provide comment, have at least 2 

months to provide comment, and in 

which all such comments and 

associated responses are made publicly 

available. All TRMs must also be 

publicly accessible over the full period 

of time in which they are being used in 

conjunction with an EM&V plan for the 

purpose of quantifying savings, and 

must be subsequently updated in the 

same manner at least every 3 years. The 

TRM must indicate, for each subject EE 

measure, the associated electricity 

savings value, the conditions under 

which the value can be applied 

(including the climate zone, building 

type, manner of implementation, 

applicable end uses, operating 

conditions, and effective useful life), 

and the manner in which the electricity 

savings value was quantified, which 

must include applicable engineering 

algorithms, source documentation, 

specific assumptions, and other relevant 

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data to support the quantification of 

savings from the subject EE measure. 

(v) All EE programs, EE projects, or EE 

measures must be quantified at time 

intervals (in years) sufficient to ensure 

that MWh savings are accurately and 

reliably quantified. Such time intervals 

must be specified and explained in the 

EM&V plan. Factors that must be taken 

into consideration when determining 

the appropriate time interval include 

the characteristics of the specific EE 

program, EE project, or EE measure, 

expected variability in electricity 

savings (where greater variability 

necessitates more frequent 

quantification), the expected scale and 

magnitude of the electricity savings 

(where greater quantities of savings 

necessitate more frequent 

quantification), and the experience 

implementing and quantifying savings 

from the resource (where less 

experience—for example, with new and 

innovative EE program types— 

necessitates more frequent 

quantification). The time intervals must 

end no sooner than the last day of the 

effective useful life of the EE program, 

EE project, or EE measure, and must last 

no longer than: 

(A) Every 4-year intervals for building 

energy codes and product standards; 

(B) Every 1, 2 or 3 years for public or 

consumer-funded EE program, EE 

project, or EE measure, as relevant for 

the type of EE program, EE project, or 

EE measure and factors listed in 

paragraph (c)(7)(v) of this section; and 

(C) Annually for commercial and 

industrial projects, unless the resource 

provider can provide a reasonable 

justification in the EM&V plan for why 

an annual time interval is not feasible, 

and can additionally explain how the 

accuracy and reliability of savings 

values will not be lessened. 

(vi) EM&V plans must specify and 

document how the EM&V components 

in paragraphs (c)(7)(vi)(A) through (E) of 

this section will be analyzed, 

considered, or otherwise addressed in 

the quantification and verification of 

electricity savings. 

(A) The effects of changes in 

independent factors on reported 

electricity savings (i.e., factors that are 

not directly related to the EE measure, 

such as weather, occupancy, and 

production levels). 

(B) The effective useful life (EUL) or 

duration of time the EE measure is 

anticipated to remain in place and 

operable with the potential to save 

electricity, which must be based on the 

application of EM&V methods, an 

industry best-practice persistence study, 

deemed estimates of effective useful life, 

or a combination of all three. 

(1) If deemed estimates of effective 

useful life are used, then they must 

specify the date by which the EE 

measure will stop saving electricity. 

(2) If industry best-practices 

persistence studies are used to modify 

an effective-useful-life value, then they 

must be conducted at least every 5 

years. 

(C) The potential sources of double 

counting, and the associated steps for 

avoiding and correcting for it, such as: 

(1) For an EE program or EE project 

with identified participants, track the 

type and number of EE measures 

implemented at the utility-customer 

level. 

(2) For an EE program or EE project 

without identified participants, such as 

point-of-sale rebates and retailer or 

manufacturer incentive programs, track 

applicable vendor, retailer, and 

manufacturer data. 

(3) For EE programs (such as those 

implemented by a utility) and EE 

projects (such as those implemented by 

an energy service company) that both 

have identified participants, use 

tracking data to avoid and correct for 

double counting that may occur across 

the two; and 

(4) For EE programs with identified 

participants and those without (such as 

retail incentives to purchase energyefficient equipment), use EE program 

tracking data for the former and use 

applicable vendor, retailer, and 

manufacturer data for the latter to avoid 

and correct for double counting that 

may occur across the two. 

(D) The EE savings verification 

approaches for ensuring that EE 

measures have been properly installed, 

are operating as intended, and therefore 

have the potential to save electricity, 

including how verification will be 

carried out within the first year of 

implementation of the EE program, EE 

project, or EE measure using bestpractice approaches, such as physical 

inspections at a customer’s premises, 

phone and mail surveys, and reviews of 

sales receipts and other documentation. 

If such approaches are documented in 

EM&V guidance issued by the 

Administrator, they will be treated as 

acceptable. 

(E) The interactive effects of EE 

programs, EE projects, or EE measures 

on electricity usage, which are increases 

or decreases in electricity usage at an 

end-use facility or premises that occurs 

outside of specific end-uses(s) targeted 

by the EE program, EE project, or EE 

measure (e.g., lighting retrofits to 

improve EE can reduce waste heat to the 

surrounding conditioned space, and 

therefore may increase the required 

electric heating load in a facility or 

premises). 

(vii) The EM&V plan must specify 

how the accuracy and reliability of the 

electricity savings of the EE program, EE 

project, or EE measure will be assessed, 

and must discuss the rigor of the 

method selected to quantify the 

electricity savings. It must also discuss 

the approaches that will be used to 

control all relevant types of bias and to 

minimize the potential for systematic 

and random error, as well as the 

program- or project-specific 

circumstances in which such bias and 

error are likely to arise. Approaches to 

minimizing bias and error are provided 

in the EM&V guidance that may be 

issued by the Administrator will be 

acceptable. 

(viii) If sampling will be used to 

quantify the electricity savings from an 

EE program, then the MWh estimates 

derived from sampling must have at 

least 90 percent confidence intervals 

whose end points are no more than +/ 

¥10 percent of the estimate, and the 

statistical precision of the associated 

estimates must be specified in the 

EM&V plan. 

(ix) All data sources and key 

assumptions used to quantify electricity 

savings must be described in the EM&V 

plan. 

(x) Any additional information 

necessary to demonstrate that the 

electricity savings were appropriately 

quantified and verified. Approaches to 

quantifying and verifying savings from 

several EE program and EE project types 

that are provided in EM&V guidance 

that may be issued by the Administrator 

will be acceptable. 

(d) You must ensure that any EM&V 

plan submitted pursuant to this subpart 

includes the following certification: 

(1) ‘‘I certify under penalty of law that 

I have personally examined, and am 

familiar with, the statements and 

information submitted in this document 

and all its attachments. Based on my 

inquiry of those individuals with 

primary responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(2) [Reserved] 

§ 62.16265 What are the requirements for 

monitoring and verification reports for 

eligible resources? 

(a) M&V report requirements. Any 

M&V report that is submitted, in 

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support of the issuance of a set-aside 

allowance that can be used in 

accordance with § 62.16240, must meet 

the requirements of this section. 

(b) General M&V report criteria. Each 

M&V report must include the 

information in paragraphs (b)(1) and (2) 

of this section. 

(1) For the first M&V report 

submitted, documentation that the 

electricity-generating resources, 

electricity-saving measures, or practices 

were installed or implemented 

consistent with the description in the 

approved eligibility application 

required in § 62.16245(a)(3). 

(2) For each M&V report submitted: 

(i) Identification of the time period 

covered by the M&V report; 

(ii) A description of how relevant 

quantification methods, protocols, 

guidelines, and guidance specified in 

the EM&V plan were applied during the 

reporting period to generate the 

quantified MWh of generation or MWh 

of electricity savings; 

(iii) Documentation (including data) 

of the energy generation and/or 

electricity savings from any activity, 

project, measure, or program addressed 

in the EM&V report, quantified and 

verified in MWh for the period covered 

by the M&V report, in accordance with 

its EM&V plan, and based on ex-post 

energy generation or savings; 

(iv) Documentation of any change in 

the energy generation or savings 

capability of the eligible resource during 

the period covered by the M&V report 

and the date on which the change 

occurred, and either certification that 

the eligible resource continued to meet 

all eligibility requirements during the 

reporting period covered by the M&V 

report or disclosure of any material 

changes to the eligible resource from the 

description of the eligible resource in 

the approved eligibility application, 

which must include any change in the 

energy generation (e.g., nameplate MW 

capacity) or electricity savings 

capability of the qualifying eligible 

resource (including the date of the 

change); and 

(v) Documentation of any change in 

ownership interest of the qualifying 

eligible resource (including the date of 

the change). 

(c) You must ensure that any M&V 

report submitted pursuant to this 

subpart includes the following 

certification: 

(1) ‘‘I certify under penalty of law that 

I have personally examined, and am 

familiar with, the statements and 

information submitted in this document 

and all its attachments. Based on my 

inquiry of those individuals with 

primary responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(2) [Reserved] 

§ 62.16270 What are the requirements for 

verification reports? 

(a) A verification report included as 

part of an eligibility application or an 

M&V report must meet the requirements 

of paragraph (b) of this section (for the 

eligibility application verification 

report) and paragraph (c) of this section 

(for the M&V report verification report) 

and include the following: 

(1) A verification statement that sets 

forth the findings of the accredited 

independent verifier, based on the 

verifier’s assessment of the information 

and data in the eligibility application or 

M&V report that is the subject of the 

verification report, including an 

assessment of whether the eligibility 

application or M&V report contains any 

material misstatements or material data 

discrepancies, and whether the 

submittal conforms with applicable 

regulatory requirements. The 

verification statement must clearly 

identify how levels of assurance and 

materiality are defined as part of the 

verifier assessment. 

(2) The following statement, signed by 

the accredited independent verifier: ‘‘I 

certify under penalty of law that I have 

personally examined, and am familiar 

with, the statements and information 

submitted in this document and all its 

attachments. Based on my personal 

knowledge and/or inquiry of those 

individuals with primary responsibility 

for obtaining the information, I certify 

that the statements and information are 

to the best of my knowledge and belief 

true, accurate, and complete. I am aware 

that there are significant penalties for 

submitting false statements and 

information or omitting required 

statements and information, including 

the possibility of fine or imprisonment.’’ 

(b) A verification report included as 

part of an eligibility application must, at 

a minimum, describe the review 

conducted by the accredited 

independent verifier and verify each of 

the following: 

(1) The eligibility of the eligible 

resource to be issued set-aside 

allowances pursuant to this regulation, 

in accordance with § 62.16245(a), 

including an analysis of the adequacy 

and validity of the information 

submitted by the authorized account 

representative to demonstrate that the 

eligible resource meets each applicable 

requirement of § 62.16245; 

(2) The eligible resource is not 

duplicative of a resource used to meet 

emission standards or a state measure in 

another approved State plan; 

(3) The eligible resource exists or the 

operation or activity will be 

implemented in the manner specified in 

the eligibility application; 

(4) That the EM&V plan meets the 

requirements of § 62.16260; 

(5) Disclosure of any mandatory or 

voluntary programs to which data is 

reported relating to the eligible resource 

(e.g., reporting of electric generation by 

a renewable energy resource to a 

renewable energy certificate tracking 

system); and 

(6) Any other information required by 

the Administrator or that the accredited 

independent verifier finds, in its 

professional opinion, is necessary to 

assess the adequacy and validity of 

information and data supplied by the 

authorized account representative. 

(c) A verification report included as 

part of an M&V report must, at a 

minimum, describe the review 

conducted by the accredited 

independent verifier and verify the 

information specified in paragraphs 

(c)(1) through (3) of this section. 

(1) The adequacy and validity of the 

information and data submitted in the 

submittal by the authorized account 

representative to quantify eligible MWh 

of electric generation or electricity 

savings during the period for which the 

authorized account representative seeks 

issuance of set-aside allowances, as well 

as all supporting information and data 

identified in the EM&V plan and M&V 

report. This analysis must include a 

quality assurance and quality control 

check of the data and ensure that all 

generation or savings data is within a 

technically feasible range for that 

specific eligible resource. 

(i) For metered generation, the data 

validity check must compare reported 

electricity generation to an engineering 

estimate of the maximum generation 

potential of the qualified renewable 

energy resource, based on, at a 

minimum, its maximum nameplate 

capacity in MW and the number of days 

since the prior cumulative meter 

reading was entered in the allowance 

tracking system. If the data entered 

exceeds the estimated technically 

feasible generation, then the reported 

data and the estimate must be analyzed 

in the verification report. 

(ii) For all electricity generated or 

saved, the accredited independent 

verifier must describe the likely source 

of any data discrepancy and determine 

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in the verification report any MWh 

generated or saved. 

(2) The M&V report meets the 

requirements of § 62.16265. 

(3) Any other information required by 

the Administrator or that the accredited 

independent verifier finds, in its 

professional opinion, is necessary to 

assess the adequacy and validity of 

information and data supplied by the 

authorized account representative. 

§ 62.16275 What is the accreditation 

procedure for independent verifiers? 

(a) Only Administrator-accredited 

independent verifiers may provide a 

verification report for an eligibility 

application or M&V report. 

(b) Applications for accreditation 

must follow a procedure and form 

specified by the Administrator which 

includes a demonstration by the verifier 

that it meets the requirements in 

paragraph (c) of this section. 

(c) Independent verifiers must meet 

each of the requirements in paragraphs 

(c)(1) through (6) of this section to be 

accredited. 

(1) Independent verifiers must have 

the skills, experience, resources 

(personnel and otherwise) to provide 

verification reports, including the 

following: 

(i) Appropriate technical qualification 

(professional engineer or otherwise) to 

evaluate the eligible resource for which 

the independent verifier is seeking 

accreditation, which may include ANSI 

accreditation under ISO 14065 for GHG 

validation and verification bodies; 

(ii) Appropriate auditing and 

accounting qualifications for financial 

and non-financial data monitoring, 

auditing, and quality assurance and 

quality control to evaluate the eligible 

resource for which the independent 

verifier is seeking accreditation; 

(iii) Knowledge of the requirements of 

the Administrator’s CO2 Mass-based 

Trading Program regulations and related 

guidance; 

(iv) Knowledge of the eligible 

resource categories for which the 

independent verifier is seeking 

accreditation, including relevant aspects 

of the design, operation, and related 

energy generation or electricity savings 

monitoring and reporting approaches for 

such eligible resources; and 

(v) Capability to perform key 

verification activities, such as 

development of a verification report; 

site visits; review and recalculation of 

reported data; review of data 

management systems; review of 

quantification methods used in 

accordance with an approved EM&V 

plan; preparation of a verification 

opinion, list of findings, and verification 

report; and internal review of the 

verification findings and report. 

(2) Independent verifiers must 

document, in the application for 

accreditation, the independent verifiers 

that will provide verification services, 

including lead verifiers, key personnel 

and any contractors or subcontractors 

(collectively, accredited independent 

verification team) and demonstrate that 

they meet the requirements of paragraph 

(c)(1) of this section. Once accredited, 

only the accredited independent 

verification team identified in the 

accreditation application and accredited 

by the State may provide a verification 

report. 

(3) An independent verifier must 

specify the eligible resource categories 

for which it is seeking accreditation, 

and an accredited independent verifier 

may only provide verification services 

related to an eligible resource category 

for which it is accredited. 

(4) Prospective independent verifiers 

must meet the requirements of 

§ 62.16280(d) through (f) and 

demonstrate that they have in place 

adequate systems and protocols to 

identify, disclose and avoid potential 

conflicts of interest. 

(5) An accredited independent verifier 

must not be debarred, suspended, or 

proposed for debarment pursuant to the 

Government-wide Debarment and 

Suspension regulations, 40 CFR part 32 

of this chapter, or the Debarment, 

Suspension and Ineligibility provisions 

of the Federal Acquisition Regulations, 

48 CFR part 9, subpart 9.4. 

(6) An accredited independent verifier 

must maintain, for its employees, and 

ensure the maintenance of, for any 

parties that it employs, professional 

liability insurance, as defined in 31 CFR 

50.5(q), through an insurance provider 

that possesses a financial strength rating 

in the top four categories from either 

Standard & Poor’s or Moody’s, 

specifically, AAA, AA, A or BBB for 

Standard & Poor’s, and Aaa, Aa, A, or 

Baa for Moody’s. Any entity covered by 

this paragraph must disclose the level of 

professional liability insurance they 

possess when entering into contracts to 

provide verification services pursuant to 

this regulation. 

(d) Requirements for maintenance of 

accreditation status. 

(1) Accredited independent verifiers 

must meet the requirements of 

§ 62.16280 when providing verification 

services for an authorized account 

representative. 

(2) The instances specified in 

§ 62.16280(d) are cause for revocation of 

a verifier’s accreditation. 

§ 62.16280 What are the procedures 

accredited independent verifiers must 

follow to avoid conflict of interest? 

(a) Accredited independent verifiers 

must not provide verification services 

for any eligible resource for which it has 

a conflict of interest (COI), which 

means: 

(1) Accredited independent verifiers 

must have, or have had, no direct or 

indirect financial interest in, or other 

financial relationships with, an eligible 

resource, or any prospective eligible 

resource, for which they seek to provide 

a verification report; 

(2) Accredited independent verifiers 

must have, or have had, no direct or 

indirect organizational or personal 

relationships with an eligible resource, 

that would impact their impartiality in 

assessing the validity and accuracy of 

the information in an eligibility 

application or M&V report; 

(3) Accredited independent verifiers 

must have, or have had, no role in the 

development and implementation of an 

eligible resource for which an 

authorized account representative seeks 

issuance of set-aside allowances, 

beyond the provision of verification 

services; 

(4) Accredited independent verifiers 

must not be compensated, financially or 

otherwise, directly or indirectly, on the 

basis of the content of its verification 

report (including eligibility approval of 

an eligible resource, the quantified and 

verified MWh in an M&V report, setaside allowance issuance, or the number 

of set-aside allowances issued); 

(5) Accredited independent verifiers 

must not own, buy, sell, or hold setaside allowances, or other financial 

derivatives related to set-aside 

allowances, or have a financial 

relationship with other parties that own, 

buy, sell, or hold set-aside allowances or 

other related financial derivatives; 

(6) An accredited independent verifier 

must not be incapable of providing an 

impartial verification report for any 

other reason; and 

(7) An accredited independent verifier 

must ensure that the subject of any 

verification report must not have the 

opportunity to review or influence any 

draft or final verification report before 

its submittal to the Administrator, and 

the accredited independent verifier 

must share any drafts of its reports with 

the Administrator at the same time as it 

shares them with the subject of the 

report. 

(b) A contract with an eligible 

resource for the provision of verification 

services will not constitute a COI. 

(c) Verification reports must include 

an attestation by the accredited 

independent verifier that it evaluated 

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and disclosed to the Administrator any 

potential COI related to an eligible 

resource. 

(d) Prior to engaging for the provision 

of verification services, an accredited 

independent verifier must demonstrate 

that it has no COI related to the eligible 

resource, as specified in paragraph (a) of 

this section. If a COI is identified for a 

person or persons within an accredited 

independent verifier for a specific 

subject or verification, in accordance 

with paragraphs (e) and (f) of this 

section, then an accredited independent 

verifier may propose to the 

Administrator steps that will be taken to 

eliminate the COI, which include 

prohibiting the person or persons with 

the conflict from any involvement in the 

matter subject to the conflict, including 

verification services, access to 

information related to the verification 

services, access to any draft or final 

verification reports, any 

communications with the person(s) 

conducting the verification services. In 

no instance shall an accredited 

independent verifier engage in 

verification services for an eligible 

resource without the approval of the 

Administrator. 

(e) Prior to engaging in verification 

services and writing a verification 

report, an accredited independent 

verifier must disclose to the 

Administrator all information necessary 

for the Administrator to evaluate a 

potential COI (including information 

concerning its ownership, past and 

current clients, related entities, as well 

as any other facts or circumstances that 

have the potential to create a COI). 

(f) Accredited verifiers have an 

ongoing obligation to disclose to the 

Administrator any facts or 

circumstances that may give rise to a 

COI as defined in paragraph (a) of this 

section. 

(g) The Administrator may reject a 

verification report from an accredited 

independent verifier, if the 

Administrator determines that the 

accredited independent verifier has a 

COI as defined in paragraph (a) of this 

section. If the Administrator rejects an 

accredited independent verifier report 

for such reasons, then the eligibility 

application or M&V report submittal 

shall be deemed incomplete and setaside allowances must not be issued 

pursuant to it. 

§ 62.16285 What is the process for the 

revocation of accreditation status for an 

independent verifier? 

(a) The Administrator may revoke the 

accreditation of an independent verifier 

at any time for cause, including for the 

reasons specified in paragraphs (a)(1) 

through (4) of this section. 

(1) Failure to fully disclose any issues 

that may lead to a COI with respect to 

an eligible resource, or other related 

entity, in accordance with § 62.16280(d) 

through (f). 

(2) The accredited independent 

verifier is no longer qualified to provide 

verification services. 

(3) Negligence in the conduct of 

verification activities, or neglect of 

responsibilities pursuant to the 

requirements of §§ 62.16270, 62.16275, 

and 62.16280. 

(4) Intentional misrepresentation of 

data in a verification report. 

(b) [Reserved] 

Designated Representatives 

§ 62.16290 How are designated 

representatives and alternate designated 

representatives authorized, and what role 

do authorized designated representatives 

and alternate designated representatives 

play? 

(a) Except as provided under 

§ 62.16300, each facility, including all 

affected EGUs at the facility, shall have 

one and only one designated 

representative, with regard to all matters 

under the CO2 Mass-based Trading 

Program. 

(1) The designated representative 

shall be selected by an agreement 

binding on the owners and operators of 

the facility and all affected EGUs at the 

facility and must act in accordance with 

the certification statement in 

§ 62.16305(a)(4)(iii). 

(2) Upon and after receipt by the 

Administrator of a complete certificate 

of representation under § 62.16305: 

(i) The designated representative shall 

be authorized and shall represent and, 

by his or her representations, actions, 

inactions, or submissions, legally bind 

each owner and operator of the facility 

and each affected EGU at the facility in 

all matters pertaining to the CO2 Massbased Trading Program, 

notwithstanding any agreement between 

the designated representative and such 

owners and operators; and 

(ii) The owners and operators of the 

facility and each affected EGU at the 

facility shall be bound by any decision 

or order issued to the designated 

representative by the Administrator 

regarding the facility or any such 

affected EGU. 

(b) Except as provided under 

§ 62.16300, each facility may have one 

and only one alternate designated 

representative, who may act on behalf of 

the designated representative. The 

agreement by which the alternate 

designated representative is selected 

must include a procedure for 

authorizing the alternate designated 

representative to act in lieu of the 

designated representative. 

(1) The alternate designated 

representative shall be selected by an 

agreement binding on the owners and 

operators of the facility and all affected 

EGUs at the facility and must act in 

accordance with the certification 

statement in § 62.16305(a)(4)(iii). 

(2) Upon and after receipt by the 

Administrator of a complete certificate 

of representation under § 62.16305: 

(i) The alternate designated 

representative must be authorized; 

(ii) Any representation, action, 

inaction, or submission by the alternate 

designated representative shall be 

deemed to be a representation, action, 

inaction, or submission by the 

designated representative; and 

(iii) The owners and operators of the 

facility and each affected EGU at the 

facility shall be bound by any decision 

or order issued to the alternate 

designated representative by the 

Administrator regarding the facility or 

any such affected EGU. 

(c) Except in this section, § 62.16375, 

and §§ 62.16295 through 62.16315, 

whenever the term ‘‘designated 

representative’’ (as distinguished from 

the term ‘‘common designated 

representative’’) is used in this subpart, 

the term shall be construed to include 

the designated representative or any 

alternate designated representative. 

§ 62.16295 What responsibilities do 

designated representatives and alternate 

designated representatives hold? 

(a) Except as provided under 

§ 62.16315 concerning delegation of 

authority to make submissions, each 

submission under the CO2 Mass-based 

Trading Program shall be made, signed, 

and certified by the designated 

representative or alternate designated 

representative for each facility and 

affected EGU for which the submission 

is made. Each such submission must 

include the following certification 

statement by the designated 

representative or alternate designated 

representative: ‘‘I am authorized to 

make this submission on behalf of the 

owners and operators of the facility or 

affected EGUs for which the submission 

is made. I certify under penalty of law 

that I have personally examined, and am 

familiar with, the statements and 

information submitted in this document 

and all its attachments. Based on my 

inquiry of those individuals with 

primary responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

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significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(b) The Administrator will accept or 

act on a submission made for a facility 

or an affected EGU only if the 

submission has been made, signed, and 

certified in accordance with paragraph 

(a) of this section and § 62.16315. 

§ 62.16300 What are the processes for 

changing designated representative, 

alternate designated representative, owners 

and operators, and affected EGUs at the 

facility? 

(a) Changing designated 

representative. The designated 

representative may be changed at any 

time upon receipt by the Administrator 

of a superseding complete certificate of 

representation under § 62.16305. 

Notwithstanding any such change, all 

representations, actions, inactions, and 

submissions by the previous designated 

representative before the time and date 

when the Administrator receives the 

superseding certificate of representation 

shall be binding on the new designated 

representative and the owners and 

operators of the facility and the affected 

EGUs at the facility. 

(b) Changing alternate designated 

representative. The alternate designated 

representative may be changed at any 

time upon receipt by the Administrator 

of a superseding complete certificate of 

representation under § 62.16305. 

Notwithstanding any such change, all 

representations, actions, inactions, and 

submissions by the previous alternate 

designated representative before the 

time and date when the Administrator 

receives the superseding certificate of 

representation shall be binding on the 

new alternate designated representative, 

the designated representative, and the 

owners and operators of the facility and 

the affected EGUs at the facility. 

(c) Changes in owners and operators. 

(1) In the event an owner or operator of 

a facility or an affected EGU at the 

facility is not included in the list of 

owners and operators in the certificate 

of representation under § 62.16305, such 

owner or operator shall be deemed to be 

subject to and bound by the certificate 

of representation, the representations, 

actions, inactions, and submissions of 

the designated representative and any 

alternate designated representative of 

the facility or affected EGU, and the 

decisions and orders of the 

Administrator, as if the owner or 

operator were included in such list. 

(2) Within 30 days after any change in 

the owners and operators of a facility or 

an affected EGU at the facility, 

including the addition or removal of an 

owner or operator, the designated 

representative or any alternate 

designated representative must submit a 

revision to the certificate of 

representation under § 62.16305 

amending the list of owners and 

operators to reflect the change. 

(d) Changes in affected EGUs at the 

facility. Within 30 days of any change in 

which affected EGUs are located at a 

facility (including the addition or 

removal of an affected EGU), the 

designated representative or any 

alternate designated representative must 

submit a certificate of representation 

under § 62.16305 amending the list of 

affected EGUs to reflect the change. 

(1) If the change is the addition of an 

affected EGU that operated (other than 

for purposes of testing by the 

manufacturer before initial installation) 

before being located at the facility, then 

the certificate of representation must 

identify, in a format prescribed by the 

Administrator, the entity from whom 

the affected EGU was purchased or 

otherwise obtained (including name, 

address, telephone number, and 

facsimile transmission number (if any)), 

the date on which the affected EGU was 

purchased or otherwise obtained, and 

the date on which the affected EGU 

became located at the facility. 

(2) If the change is the removal of an 

affected EGU, then the certificate of 

representation must identify, in a format 

prescribed by the Administrator, the 

entity to which the affected EGU was 

sold or that otherwise obtained the 

affected EGU (including name, address, 

telephone number, email address and 

facsimile transmission number (if any)), 

the date on which the affected EGU was 

sold or otherwise obtained, and the date 

on which the affected EGU became no 

longer located at the facility. 

§ 62.16305 What must be included in a 

certificate of representation? 

(a) A complete certificate of 

representation for a designated 

representative or an alternate designated 

representative must include the 

following elements in a format 

prescribed by the Administrator: 

(1) Identification of the facility, and 

each affected EGU at the facility, for 

which the certificate of representation is 

submitted, including facility and 

affected EGU names, facility category 

and NAICS code (or, in the absence of 

a NAICS code, an equivalent code), 

State, plant code, county, latitude and 

longitude, unit identification number 

and type, identification number and 

nameplate capacity (in MWe, rounded 

to the nearest tenth) of each generator 

served by each such affected EGU, 

actual or projected date of 

commencement of commercial 

operation, net summer capacity at the 

affect EGU, and a statement of whether 

such facility is located in Indian 

country. If a projected date of 

commencement of commercial 

operation is provided, then the actual 

date of commencement of commercial 

operation must be provided when such 

information becomes available. 

(2) The name, address, email address 

(if any), telephone number, and 

facsimile transmission number (if any) 

of the designated representative and any 

alternate designated representative. 

(3) A list of the owners and operators 

of the facility and of each affected EGU 

at the facility. 

(4) The following certification 

statements by the designated 

representative and any alternate 

designated representative: 

(i) ‘‘I certify that I was selected as the 

designated representative or alternate 

designated representative, as applicable, 

by an agreement binding on the owners 

and operators of the facility and each 

affected EGU at the facility’’; and 

(ii) ‘‘I certify that I have all the 

necessary authority to carry out my 

duties and responsibilities under the 

CO2 Mass-based Trading Program on 

behalf of the owners and operators of 

the facility and of each affected EGU at 

the facility and that each such owner 

and operator shall be fully bound by my 

representations, actions, inactions, or 

submissions and by any decision or 

order issued to me by the Administrator 

regarding the facility or unit.’’ 

(iii) ‘‘Where there are multiple 

holders of a legal or equitable title to, or 

a leasehold interest in, an affected EGU, 

or where a utility or industrial customer 

purchases power from an affected EGU 

under a life-of-the-unit, firm power 

contractual arrangement, I certify that: I 

have given a written notice of my 

selection as the ‘designated 

representative’ or ‘alternate designated 

representative’, as applicable, and of the 

agreement by which I was selected to 

each owner and operator of the facility 

and of each affected EGU at the facility; 

and CO2 allowances and proceeds of 

transactions involving CO2 Mass-based 

Trading allowances will be deemed to 

be held or distributed in proportion to 

each holder’s legal, equitable, leasehold, 

or contractual reservation or 

entitlement, except that, if such 

multiple holders have expressly 

provided for a different distribution of 

CO2 allowances by contract, then CO2

allowances and proceeds of transactions 

involving CO2 Mass-based Trading 

allowances will be deemed to be held or 

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distributed in accordance with the 

contract.’’ 

(5) The signature of the designated 

representative and any alternate 

designated representative and the dates 

signed. 

(b) Unless otherwise required by the 

Administrator, documents of agreement 

referred to in the certificate of 

representation shall not be submitted to 

the Administrator. The Administrator 

shall not be under any obligation to 

review or evaluate the sufficiency of 

such documents, if submitted. 

§ 62.16310 What is the Administrator’s role 

in objections concerning designated 

representatives and alternate designated 

representatives? 

(a) Once a complete certificate of 

representation under § 62.16305 has 

been submitted and received, the 

Administrator will rely on the certificate 

of representation unless and until a 

superseding complete certificate of 

representation under § 62.16305 is 

received by the Administrator. 

(b) Except as provided in paragraph 

(a) of this section, no objection or other 

communication submitted to the 

Administrator concerning the 

authorization, or any representation, 

action, inaction, or submission, of a 

designated representative or alternate 

designated representative shall affect 

any representation, action, inaction, or 

submission of the designated 

representative or alternate designated 

representative or the finality of any 

decision or order by the Administrator 

under the CO2 Mass-based Trading 

Program. 

(c) The Administrator will not 

adjudicate any private legal dispute 

concerning the authorization or any 

representation, action, inaction, or 

submission of any designated 

representative or alternate designated 

representative, including private legal 

disputes concerning the proceeds of CO2

allowance transfers. 

§ 62.16315 What process must designated 

representatives and alternate designated 

representatives follow to delegate their 

authority? 

(a) A designated representative may 

delegate, to one or more natural persons, 

his or her authority to make an 

electronic submission to the 

Administrator provided for or required 

under this subpart. 

(b) An alternate designated 

representative may delegate, to one or 

more natural persons, his or her 

authority to make an electronic 

submission to the Administrator 

provided for or required under this 

subpart. 

(c) In order to delegate authority to a 

natural person to make an electronic 

submission to the Administrator in 

accordance with paragraph (a) or (b) of 

this section, the designated 

representative or alternate designated 

representative, as appropriate, must 

submit to the Administrator a notice of 

delegation, in a format prescribed by the 

Administrator, that includes the 

elements in paragraphs (c)(1) through 

(4) of this section. 

(1) The name, address, email address, 

telephone number, and facsimile 

transmission number (if any) of such 

designated representative or alternate 

designated representative. 

(2) The name, address, email address, 

telephone number, and facsimile 

transmission number (if any) of each 

such natural person (referred to in this 

section as an ‘‘agent’’). 

(3) For each such natural person, a list 

of the type or types of electronic 

submissions under paragraph (a) or (b) 

of this section for which authority is 

delegated to him or her. 

(4) The following certification 

statements by such designated 

representative or alternate designated 

representative: 

(i) ‘‘I agree that any electronic 

submission to the Administrator that is 

made by an agent identified in this 

notice of delegation and of a type listed 

for such agent in this notice of 

delegation and that is made when I am 

a designated representative or alternate 

designated representative, as 

appropriate, and before this notice of 

delegation is superseded by another 

notice of delegation under § 62.16315(d) 

shall be deemed to be an electronic 

submission by me’’; and 

(ii) ‘‘Until this notice of delegation is 

superseded by another notice of 

delegation under § 62.16315(d), I agree 

to maintain an email account and to 

notify the Administrator immediately of 

any change in my email address unless 

all delegation of authority by me under 

§ 62.16315 is terminated.’’ 

(d) A notice of delegation submitted 

under paragraph (c) of this section shall 

be effective, with regard to the 

designated representative or alternate 

designated representative identified in 

such notice, upon receipt of such notice 

by the Administrator and until receipt 

by the Administrator of a superseding 

notice of delegation submitted by such 

designated representative or alternate 

designated representative, as 

appropriate. The superseding notice of 

delegation may replace any previously 

identified agent, add a new agent, or 

eliminate entirely any delegation of 

authority. 

(e) Any electronic submission covered 

by the certification in paragraph (c)(4)(i) 

of this section and made in accordance 

with a notice of delegation effective 

under paragraph (d) of this section shall 

be deemed to be an electronic 

submission by the designated 

representative or alternate designated 

representative submitting such notice of 

delegation. 

Monitoring, Recordkeeping, Reporting 

§ 62.16320 How are compliance accounts 

and general accounts established? 

(a) Compliance accounts. Upon 

receipt of a complete certificate of 

representation under § 62.16305, the 

Administrator will establish a 

compliance account for the facility for 

which the certificate of representation 

was submitted, unless the facility 

already has a compliance account. The 

designated representative and any 

alternate designated representative of 

the facility shall be the authorized 

account representative and the alternate 

authorized account representative 

respectively of the compliance account. 

(b) Retirement accounts. (1) A 

retirement account, into which 

allowances held in a compliance 

account for an affected EGU are 

surrendered by the owner or operator of 

an affected EGU, for use in 

demonstrating compliance with its 

emission standards. The retirement 

account may only be held by the 

Administrator, and allowances 

deposited into it are permanently 

retired. Once an allowance is retired, 

the allowance shall no longer be 

transferable to another account in that 

allowance tracking system or any other 

allowance tracking system. 

(2) [Reserved] 

(c) General accounts—(1) Application 

for a general account. (i) Any person 

may apply to open a general account, for 

the purpose of holding and transferring 

CO2 allowances, by submitting to the 

Administrator a complete application 

for a general account. Such application 

must designate one and only one 

authorized account representative and 

may designate one and only one 

alternate authorized account 

representative who may act on behalf of 

the authorized account representative. 

(A) The authorized account 

representative and alternate authorized 

account representative shall be selected 

by an agreement binding on the persons 

who have an ownership interest with 

respect to CO2 allowances held in the 

general account. 

(B) The agreement by which the 

alternate authorized account 

representative is selected must include 

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a procedure for authorizing the alternate 

authorized account representative to act 

in lieu of the authorized account 

representative. 

(ii) A complete application for a 

general account must include the 

following elements in a format 

prescribed by the Administrator: 

(A) Name, mailing address, email 

address (if any), telephone number, and 

facsimile transmission number (if any) 

of the authorized account representative 

and any alternate authorized account 

representative; 

(B) An identifying name for the 

general account; 

(C) A list of all persons subject to a 

binding agreement for the authorized 

account representative and any alternate 

authorized account representative to 

represent their ownership interest with 

respect to the CO2 allowances held in 

the general account; 

(D) The following certification 

statement by the authorized account 

representative and any alternate 

authorized account representative: ‘‘I 

certify that I was selected as the 

authorized account representative or the 

alternate authorized account 

representative, as applicable, by an 

agreement that is binding on all persons 

who have an ownership interest with 

respect to CO2 allowances held in the 

general account. I certify that I have all 

the necessary authority to carry out my 

duties and responsibilities under the 

CO2 Mass-based Trading Program on 

behalf of such persons and that each 

such person shall be fully bound by my 

representations, actions, inactions, or 

submissions and by any decision or 

order issued to me by the Administrator 

regarding the general account’’; and 

(E) The signature of the authorized 

account representative and any alternate 

authorized account representative and 

the dates signed. 

(iii) Unless otherwise required by the 

Administrator, documents of agreement 

referred to in the application for a 

general account shall not be submitted 

to the Administrator. The Administrator 

shall not be under any obligation to 

review or evaluate the sufficiency of 

such documents, if submitted. 

(2) Authorization of authorized 

account representative and alternate 

authorized account representative. (i) 

Upon receipt by the Administrator of a 

complete application for a general 

account under paragraph (c)(1) of this 

section, the Administrator will establish 

a general account for the person or 

persons for whom the application is 

submitted, and upon and after such 

receipt by the Administrator: 

(A) The authorized account 

representative of the general account 

shall be authorized and shall represent 

and, by his or her representations, 

actions, inactions, or submissions, 

legally bind each person who has an 

ownership interest with respect to CO2

allowances held in the general account 

in all matters pertaining to the CO2

Mass-based Trading Program, 

notwithstanding any agreement between 

the authorized account representative 

and such person; 

(B) Any alternate authorized account 

representative shall be authorized, and 

any representation, action, inaction, or 

submission by any alternate authorized 

account representative shall be deemed 

to be a representation, action, inaction, 

or submission by the authorized account 

representative; and 

(C) Each person who has an 

ownership interest with respect to CO2

allowances held in the general account 

shall be bound by any decision or order 

issued to the authorized account 

representative or alternate authorized 

account representative by the 

Administrator regarding the general 

account. 

(ii) Except as provided in paragraph 

(c)(5) of this section concerning 

delegation of authority to make 

submissions, each submission 

concerning the general account shall be 

made, signed, and certified by the 

authorized account representative or 

any alternate authorized account 

representative for the persons having an 

ownership interest with respect to CO2

allowances held in the general account. 

Each such submission must include the 

following certification statement by the 

authorized account representative or 

any alternate authorized account 

representative: ‘‘I am authorized to 

make this submission on behalf of the 

persons having an ownership interest 

with respect to the CO2 allowances held 

in the general account. I certify under 

penalty of law that I have personally 

examined, and am familiar with, the 

statements and information submitted 

in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(iii) Except in this section, whenever 

the term ‘‘authorized account 

representative’’ is used in this subpart, 

the term shall be construed to include 

the authorized account representative or 

any alternate authorized account 

representative. 

(3) Changing authorized account 

representative and alternate authorized 

account representative; changes in 

persons with ownership interest. 

(i) The authorized account 

representative of a general account may 

be changed at any time upon receipt by 

the Administrator of a superseding 

complete application for a general 

account under paragraph (c)(1) of this 

section. Notwithstanding any such 

change, all representations, actions, 

inactions, and submissions by the 

previous authorized account 

representative before the time and date 

when the Administrator receives the 

superseding application for a general 

account shall be binding on the new 

authorized account representative and 

the persons with an ownership interest 

with respect to the CO2 allowances in 

the general account. 

(ii) The alternate authorized account 

representative of a general account may 

be changed at any time upon receipt by 

the Administrator of a superseding 

complete application for a general 

account under paragraph (c)(1) of this 

section. Notwithstanding any such 

change, all representations, actions, 

inactions, and submissions by the 

previous alternate authorized account 

representative before the time and date 

when the Administrator receives the 

superseding application for a general 

account shall be binding on the new 

alternate authorized account 

representative, the authorized account 

representative, and the persons with an 

ownership interest with respect to the 

CO2 allowances in the general account. 

(iii)(A) In the event a person having 

an ownership interest with respect to 

CO2 allowances in the general account 

is not included in the list of such 

persons in the application for a general 

account, such person shall be deemed to 

be subject to and bound by the 

application for a general account, the 

representation, actions, inactions, and 

submissions of the authorized account 

representative and any alternate 

authorized account representative of the 

account, and the decisions and orders of 

the Administrator, as if the person were 

included in such list. 

(B) Within 30 days after any change 

in the persons having an ownership 

interest with respect to CO2 allowances 

in the general account, including the 

addition or removal of a person, the 

authorized account representative or 

any alternate authorized account 

representative must submit a revision to 

the application for a general account 

amending the list of persons having an 

ownership interest with respect to the 

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CO2 allowances in the general account 

to include the change. 

(4) Objections concerning authorized 

account representative and alternate 

authorized account representative. 

(i) Once a complete application for a 

general account under paragraph (c)(1) 

of this section has been submitted and 

received, the Administrator will rely on 

the application unless and until a 

superseding complete application for a 

general account under paragraph (c)(1) 

of this section is received by the 

Administrator. 

(ii) Except as provided in paragraph 

(c)(4)(i) of this section, no objection or 

other communication submitted to the 

Administrator concerning the 

authorization, or any representation, 

action, inaction, or submission of the 

authorized account representative or 

any alternate authorized account 

representative of a general account shall 

affect any representation, action, 

inaction, or submission of the 

authorized account representative or 

any alternate authorized account 

representative or the finality of any 

decision or order by the Administrator 

under the CO2 Mass-based Trading 

Program. 

(iii) The Administrator will not 

adjudicate any private legal dispute 

concerning the authorization or any 

representation, action, inaction, or 

submission of the authorized account 

representative or any alternate 

authorized account representative of a 

general account, including private legal 

disputes concerning the proceeds of CO2

allowance transfers. 

(5) Delegation by authorized account 

representative and alternate authorized 

account representative. (i) An 

authorized account representative of a 

general account may delegate, to one or 

more natural persons, his or her 

authority to make an electronic 

submission to the Administrator 

provided for or required under this 

subpart. 

(ii) An alternate authorized account 

representative of a general account may 

delegate, to one or more natural persons, 

his or her authority to make an 

electronic submission to the 

Administrator provided for or required 

under this subpart. 

(iii) In order to delegate authority to 

a natural person to make an electronic 

submission to the Administrator in 

accordance with paragraph (c)(5)(i) or 

(ii) of this section, the authorized 

account representative or alternate 

authorized account representative, as 

appropriate, must submit to the 

Administrator a notice of delegation, in 

a format prescribed by the 

Administrator, that includes the 

following elements: 

(A) The name, address, email address, 

telephone number, and facsimile 

transmission number (if any) of such 

authorized account representative or 

alternate authorized account 

representative; 

(B) The name, address, email address, 

telephone number, and facsimile 

transmission number (if any) of each 

such natural person (referred to in this 

section as an ‘‘agent’’); 

(C) For each such natural person, a 

list of the type or types of electronic 

submissions under paragraph (c)(5)(i) or 

(ii) of this section for which authority is 

delegated to him or her; 

(D) The following certification 

statement by such authorized account 

representative or alternate authorized 

account representative: ‘‘I agree that any 

electronic submission to the 

Administrator that is made by an agent 

identified in this notice of delegation 

and of a type listed for such agent in 

this notice of delegation and that is 

made when I am an authorized account 

representative or alternate authorized 

representative, as appropriate, and 

before this notice of delegation is 

superseded by another notice of 

delegation under § 62.16320(c)(5)(iv) 

shall be deemed to be an electronic 

submission by me’’; and 

(E) The following certification 

statement by such authorized account 

representative or alternate authorized 

account representative: ‘‘Until this 

notice of delegation is superseded by 

another notice of delegation under 

§ 62.16320(c)(5)(iv), I agree to maintain 

an email account and to notify the 

Administrator immediately of any 

change in my email address unless all 

delegation of authority by me under 

§ 62.16320(c)(5) is terminated.’’ 

(iv) A notice of delegation submitted 

under paragraph (c)(5)(iii) of this section 

shall be effective, with regard to the 

authorized account representative or 

alternate authorized account 

representative identified in such notice, 

upon receipt of such notice by the 

Administrator and until receipt by the 

Administrator of a superseding notice of 

delegation submitted by such 

authorized account representative or 

alternate authorized account 

representative, as appropriate. The 

superseding notice of delegation may 

replace any previously identified agent, 

add a new agent, or eliminate entirely 

any delegation of authority. 

(v) Any electronic submission covered 

by the certification in paragraph 

(c)(5)(iii)(D) of this section and made in 

accordance with a notice of delegation 

effective under paragraph (c)(5)(iv) of 

this section shall be deemed to be an 

electronic submission by the designated 

representative or alternate designated 

representative submitting such notice of 

delegation. 

(6) Closing a general account. (i) The 

authorized account representative or 

alternate authorized account 

representative of a general account may 

submit to the Administrator a request to 

close the account. Such request must 

include a correctly submitted CO2

allowance transfer under § 62.16330 for 

any CO2 allowances in the account to 

one or more other ATCS accounts. 

(ii) If a general account has no CO2

allowance transfers to or from the 

account for a 12-month period or longer 

and does not contain any CO2

allowances, then the Administrator may 

notify the authorized account 

representative for the account that the 

account will be closed 30 days after the 

notice is sent. The account will be 

closed after the 30-day period unless, 

before the end of the 30-day period, the 

Administrator receives a correctly 

submitted CO2 allowance transfer under 

§ 62.16330 to the account or a statement 

submitted by the authorized account 

representative or alternate authorized 

account representative demonstrating to 

the satisfaction of the Administrator 

good cause as to why the account 

should not be closed. 

(d) Account identification. The 

Administrator will assign a unique 

identifying number to each account 

established under paragraphs (a) 

through (c) of this section. 

(e) Responsibilities of authorized 

account representative and alternate 

authorized account representative. After 

the establishment of a compliance 

account or general account, the 

Administrator will accept or act on a 

submission pertaining to the account, 

including, but not limited to, 

submissions concerning the deduction 

or transfer of CO2 allowances in the 

account, only if the submission has been 

made, signed, and certified in 

accordance with §§ 62.16295(a) and 

62.16315 or paragraphs (c)(2)(ii) and 

(c)(5) of this section. 

§ 62.16325 When will CO2 allowances be 

recorded in compliance accounts? 

(a) By June 1, 2021, and by June 1 of 

each year prior to the beginning of each 

compliance period thereafter, the 

Administrator will record in each 

facility’s compliance account the CO2

allowances allocated to the affected 

EGUs at the facility in accordance with 

§ 62.16240(a), or with a state allowancedistribution methodology approved 

under subpart UUUU of part 60 of this 

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chapter, for the upcoming compliance 

period. 

(b) Except as specified in paragraph 

(a) of this section, the Administrator 

will record an allocation in the 

appropriate ATCS account by the date 

on which any allocation of CO2

allowances to a recipient must be made 

by or submitted to the Administrator in 

accordance with either § 62.16240 or 

with state allowance-distribution 

methodology approved under subpart 

UUUU of part 60 of this chapter. 

(c) When recording the allocation of 

CO2 allowances to an affected EGU or 

other entity in an ATCS account, the 

Administrator will assign each CO2

allowance a unique serial number that 

will include digits identifying the year 

of the compliance period for which the 

CO2 allowance is allocated. 

(d) By December 1, 2021 and 

December 1 of each year thereafter, the 

Administrator will record in each 

renewable energy project’s general 

account, the CO2 allowances allocated 

from the renewable energy set-aside to 

the project in accordance with 

§ 62.16245(a), for the following year. 

(e) By November 1 of the first year of 

each compliance period beginning in 

2025, and each compliance period 

thereafter, the Administrator will record 

in each facility’s compliance account 

the CO2 allowances allocated from the 

output-based set-aside to the eligible 

EGUs at the facility in accordance with 

§ 62.16245(b) or with a state allowancedistribution methodology approved 

under subpart UUUU of part 60 of this 

chapter, for the following year. 

§ 62.16330 How must transfers of CO2

allowances be submitted? 

(a) An authorized account 

representative seeking recordation of a 

CO2 allowance transfer must submit the 

transfer to the Administrator. 

(b) A CO2 allowance transfer is 

correctly submitted if: 

(1) The transfer includes the following 

elements, in a format prescribed by the 

Administrator: 

(i) The account numbers established 

by the Administrator for both the 

transferor and transferee accounts; 

(ii) The serial number of each CO2

allowance that is in the transferor 

account and is to be transferred; and 

(iii) The name and signature of the 

authorized account representative of the 

transferor account and the date signed; 

and 

(2) When the Administrator attempts 

to record the transfer, the transferor 

account includes each CO2 allowance 

identified by serial number in the 

transfer. 

§ 62.16335 When will CO2 allowance 

transfers be recorded? 

(a) Within 5 business days (except as 

provided in paragraph (b) of this 

section) of receiving a CO2 allowance 

transfer that is correctly submitted 

under § 62.16330, the Administrator 

will record a CO2 allowance transfer by 

moving each CO2 allowance from the 

transferor account to the transferee 

account as specified in the transfer. 

(b) A CO2 allowance transfer to or 

from a compliance account that is 

submitted for recordation after the 

allowance transfer deadline for a 

compliance period and that includes 

any CO2 allowances allocated for any 

compliance period before such 

allowance transfer deadline will not be 

recorded until after the Administrator 

completes the deductions from such 

compliance account under § 62.16340 

for the compliance period immediately 

before such allowance transfer deadline. 

(c) Where a CO2 allowance transfer is 

not correctly submitted under 

§ 62.16330, the Administrator will not 

record such transfer. 

(d) Within 5 business days of 

recordation of a CO2 allowance transfer 

under paragraphs (a) and (b) of the 

section, the Administrator will notify 

the authorized account representatives 

of both the transferor and transferee 

accounts. 

(e) Within 10 business days of receipt 

of a CO2 allowance transfer that is not 

correctly submitted under § 62.16330, 

the Administrator will notify the 

authorized account representatives of 

both accounts subject to the transfer of: 

(1) A decision not to record the 

transfer; and 

(2) The reasons for such nonrecordation. 

§ 62.16340 How will deductions for 

compliance with a CO2 emission standard 

occur? 

(a) Availability for deduction for 

compliance. CO2 allowances are 

available to be deducted for compliance 

with a facility’s CO2 emission standard 

for a compliance period only if the CO2

allowances: 

(1) Were allocated for a year in such 

compliance period or a prior 

compliance period; and 

(2) Are held in the facility’s 

compliance account as of the allowance 

transfer deadline for such compliance 

period. 

(b) Deductions for compliance. After 

the recordation, in accordance with 

§ 62.16335, of CO2 allowance transfers 

submitted by the allowance transfer 

deadline for a compliance period, the 

Administrator will deduct from each 

facility’s compliance account CO2

allowances available under paragraph 

(a) of this section in order to determine 

whether the facility meets the CO2

emission standard for such compliance 

period, as follows: 

(1) Until the amount of CO2

allowances deducted equals the number 

of tons of total CO2 emissions from all 

affected EGUs at the facility for such 

compliance period; or 

(2) If there are insufficient CO2

allowances to complete the deductions 

in paragraph (b)(1) of this section, until 

no more CO2 allowances available under 

paragraph (a) of this section remain in 

the compliance account. 

(c)(1) Identification of CO2 allowances 

by serial number. The authorized 

account representative for a facility’s 

compliance account may request that 

specific CO2 allowances, identified by 

serial number, in the compliance 

account be deducted for emissions or 

excess emissions for a compliance 

period in accordance with paragraph (b) 

or (d) of this section. In order to be 

complete, such request must be 

submitted to the Administrator by the 

allowance transfer deadline for such 

compliance period and include, in a 

format prescribed by the Administrator, 

the identification of the facility and the 

appropriate serial numbers. 

(2) First-in, first-out. The 

Administrator will deduct CO2

allowances under paragraph (b) or (d) of 

this section from the facility’s 

compliance account in accordance with 

a complete request under paragraph 

(c)(1) of this section or, in the absence 

of such request or in the case of 

identification of an insufficient amount 

of CO2 allowances in such request, on 

a first-in, first-out accounting basis in 

the following order: 

(i) Any CO2 allowances that were 

allocated to the affected EGUs at the 

facility and not transferred out of the 

compliance account, in the order of 

recordation; and then 

(ii) Any CO2 allowances that were 

allocated to any affected EGU or other 

entity and transferred to and recorded in 

the compliance account pursuant to this 

subpart, in the order of recordation. 

(d) Deductions for excess emissions. 

After making the deductions for 

compliance under paragraph (b) of this 

section for a compliance period in a 

year in which the facility has excess 

emissions, the Administrator will 

deduct from the facility’s compliance 

account an amount of CO2 allowances, 

allocated for a compliance period in a 

prior year or the compliance period in 

the year of the excess emissions or in 

the immediately following year, equal to 

two times the number of tons of the 

facility’s excess emissions. 

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(e) Recordation of deductions. The 

Administrator will record in the 

appropriate compliance account all 

deductions from such an account under 

paragraphs (b) and (d) of this section. 

§ 62.16345 What monitoring requirements 

must I comply with? 

(a) The owner or operator of an 

affected EGU must prepare a monitoring 

plan in accordance with the applicable 

provisions in § 75.53(g) and (h) of this 

chapter, unless such a plan is already in 

place under another program that 

requires CO2 mass emissions to be 

monitored and reported according to 

part 75 of this chapter. You must follow 

the requirements described in 

paragraphs (a)(1) through (8) of this 

section to monitor emissions and net 

energy output at your affected EGU. 

(1) For each operating hour, calculate 

the hourly CO2 mass (tons) according to 

paragraph (a)(4) or (5) of this section, 

except that a complete data record is 

required, i.e., CO2 mass emissions must 

be reported for each operating hour. 

Therefore, substitute data values 

recorded under part 75 of this chapter 

for CO2 concentration, stack gas flow 

rate, stack gas moisture content, fuel 

flow rate and/or gross calorific value 

(GCV) must be used in the calculations; 

and 

(2) Sum all of the hourly CO2 mass 

emissions values over the entire 

compliance period. 

(3) The owner or operator of an 

affected EGU must install, calibrate, 

maintain, and operate a sufficient 

number of watt meters to continuously 

measure and record on an hourly basis 

net electric output. Measurements must 

be performed using 0.2 accuracy class 

electricity metering instrumentation and 

calibration procedures as specified 

under ANSI Standards No. C12.20. 

Further, the owner or operator of an 

affected EGU that is a combined heat 

and power facility must install, 

calibrate, maintain and operate 

equipment to continuously measure and 

record on an hourly basis useful thermal 

output and, if applicable, mechanical 

output, which are used with net electric 

output to determine net energy output 

(Pnet). The owner or operator must 

calculate net energy output according to 

paragraphs (a)(6)(i)(A) and (B) of this 

section. 

(4) The owner or operator of an 

affected EGU must measure and report 

the hourly CO2 mass emissions (lbs) 

from each affected unit using the 

procedures in paragraphs (a)(4)(i) 

through (vi) of this section, except as 

otherwise provided in paragraph (a)(5) 

of this section. 

(i) The owner or operator of an 

affected EGU must install, certify, 

operate, maintain, and calibrate a CO2

continuous emissions monitoring 

system (CEMS) to directly measure and 

record CO2 concentrations in the 

affected EGU exhaust gases emitted to 

the atmosphere and an exhaust gas flow 

rate monitoring system according to 

§ 75.10(a)(3)(i) of this chapter. However, 

when an O2 monitor is used this way, 

it only quantifies the combustion CO2; 

therefore, if the EGU is equipped with 

emission controls that produce noncombustion CO2 (e.g., from sorbent 

injection), then this additional CO2 must 

be accounted for, in accordance with 

section 3 of appendix G to part 75 of 

this chapter. As an alternative to direct 

measurement of CO2 concentration, 

provided that the affected EGU does not 

use carbon separation (e.g., carbon 

capture and storage), the owner or 

operator of an affected EGU may use 

data from a certified oxygen (O2) 

monitor to calculate hourly average CO2

concentrations, in accordance with 

§ 75.10(a)(3)(iii) of this chapter. If CO2

concentration is measured on a dry 

basis, then the owner or operator of the 

affected EGU must also install, certify, 

operate, maintain, and calibrate a 

continuous moisture monitoring system, 

according to § 75.11(b) of this chapter. 

Alternatively, the owner or operator of 

an affected EGU may either use an 

appropriate fuel-specific default 

moisture value from § 75.11(b) or submit 

a petition to the Administrator under 

§ 75.66 of this chapter for a site-specific 

default moisture value. 

(ii) Calculate the hourly CO2 mass 

emission rate (tons/hr), either from 

Equation F–11 in Appendix F to part 75 

of this chapter (if CO2 concentration is 

measured on a wet basis), or by 

following the procedure in section 4.2 of 

Appendix F to part 75 of this chapter (if 

CO2 concentration is measured on a dry 

basis). CO2 mass emissions must be 

reported for each operating hour. 

Therefore, substitute data values 

recorded under part 75 of this chapter 

for CO2 concentration, stack gas flow 

rate, stack gas moisture content, fuel 

flow rate and/or GCV must be used in 

the calculations. 

(iii) Next, multiply each hourly CO2

mass emission rate by the EGU or stack 

operating time in hours (as defined in 

§ 72.2 of this chapter), to convert it to 

tons of CO2. Multiply the result by 2000 

lb/ton to convert it to lb. 

(iv) The hourly CO2 tons/hr values 

and EGU (or stack) operating times used 

to calculate CO2 mass emissions are 

required to be recorded under § 75.57(e) 

of this chapter and must be reported 

electronically under § 75.64(a)(6) of this 

chapter, if required by a plan. The 

owner or operator must use these data, 

or equivalent data, to calculate the 

hourly CO2 mass emissions. 

(v) Sum all of the hourly CO2 mass 

emissions values that were calculated 

according to procedures specified in 

paragraph (a)(4)(ii) of this section over 

the entire compliance period. 

(vi) For each continuous monitoring 

system used to determine the CO2 mass 

emissions from an affected EGU, the 

monitoring system must meet the 

applicable certification and quality 

assurance procedures in § 75.20 of this 

chapter and Appendices A and B to part 

75 of this chapter. 

(5) The owner or operator of an 

affected EGU that exclusively combusts 

liquid fuel and/or gaseous fuel may, as 

an alternative to complying with 

paragraph (a)(4) of this section, 

determine the hourly CO2 mass 

emissions according to paragraphs 

(a)(5)(i) through (vi) of this section. 

(i) Implement the applicable 

procedures in appendix D to part 75 of 

this chapter to determine hourly EGU 

heat input rates (MMBtu/h), based on 

hourly measurements of fuel flow rate 

and periodic determinations of the gross 

calorific value (GCV) of each fuel 

combusted. The fuel flow meter(s) used 

to measure the hourly fuel flow rates 

must meet the applicable certification 

and quality-assurance requirements in 

sections 2.1.5 and 2.1.6 of appendix D 

(except for qualifying commercial 

billing meters). The fuel GCV must be 

determined in accordance with section 

2.2 or 2.3 of appendix D, as applicable. 

(ii) For each measured hourly heat 

input rate, use Equation G–4 in 

Appendix G to part 75 of this chapter to 

calculate the hourly CO2 mass emission 

rate (tons/hr). 

(iii) Determine the hourly CO2 mass 

emission rate (tons/hr) using the 

procedures specified in paragraph 

(a)(4)(ii) of this section and multiply it 

by the EGU or stack operating time in 

hours (as defined in § 72.2 of this 

chapter), to convert to tons of CO2. 

Then, multiply the result by 2000 lb/ton 

to convert to lb. 

(iv) The hourly CO2 tons/hr values 

and EGU (or stack) operating times used 

to calculate CO2 mass emissions are 

required to be recorded under § 75.57(e) 

of this chapter and must be reported 

electronically under § 75.64(a)(6), if 

required by a plan. You must use these 

data, or equivalent data, to calculate the 

hourly CO2 mass emissions. 

(v) Sum all of the hourly CO2 mass 

emissions values (lb) that were 

calculated according to procedures 

specified in paragraph (a)(5)(iii) of this 

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section over the entire compliance 

period. 

(vi) The owner or operator of an 

affected EGU may determine sitespecific carbon-based F-factors (Fc) 

using Equation F–7b in section 3.3.6 of 

appendix F to part 75 of this chapter, 

and may use these Fc values in the 

emissions calculations instead of using 

the default Fc values in the Equation G– 

4 nomenclature. 

(6) The owner or operator of an 

affected EGU must install, calibrate, 

maintain, and operate a sufficient 

number of watt meters to continuously 

measure and record on an hourly basis 

net electric output. Measurements must 

be performed using 0.2 accuracy class 

electricity metering instrumentation and 

calibration procedures as specified 

under ANSI Standards No. C12.20. 

Further, the owner or operator of an 

affected EGU that is a combined heat 

and power facility must install, 

calibrate, maintain and operate 

equipment to continuously measure and 

record on an hourly basis useful thermal 

output and, if applicable, mechanical 

output, which are used with net electric 

output to determine net energy output. 

The owner or operator must calculate 

net energy output according to 

paragraph (a)(6)(i) of this section. 

(i) For each operating hour of a 

compliance period that was used in 

paragraph (a)(4) or (5) of this section to 

calculate the total CO2 mass emissions, 

you must determine Pnet (the 

corresponding hourly net energy output 

in MWh) according to the procedures in 

paragraphs (a)(6)(i)(A) and (B) of this 

section, as appropriate for the type of 

affected EGU(s). For an operating hour 

in which a valid CO2 mass emissions 

value is determined according to 

paragraph (a)(4) or (5) of this section, if 

there is no gross or net electrical output, 

but there is mechanical or useful 

thermal output, you must still 

determine the net energy output for that 

hour. In addition, for an operating hour 

in which a valid CO2 mass emissions 

value is determined according to 

paragraph (a)(4) or (5) of this section, 

but there is no (i.e., zero) gross 

electrical, mechanical, or useful thermal 

output, you must use that hour in the 

compliance determination. For hours or 

partial hours where the gross electric 

output is equal to or less than the 

auxiliary loads, net electric output must 

be counted as zero for this calculation. 

(A) Calculate Pnet for your affected 

EGU using the following equation. All 

terms in the equation must be expressed 

in units of megawatt-hours (MWh). To 

convert each hourly net energy output 

value reported under part 75 of this 

chapter to MWh, multiply by the 

corresponding EGU or stack operating 

time. 

Where: 

Pnet = Net energy output of your affected EGU 

in MWh. 

(Pe)ST = Electric energy output plus 

mechanical energy output (if any) of 

steam turbines in MWh. 

(Pe)CT = Electric energy output plus 

mechanical energy output (if any) of 

stationary combustion turbine(s) in 

MWh. 

(Pe)IE = Electric energy output plus 

mechanical energy output (if any) of 

your affected EGU’s integrated 

equipment that provides electricity or 

mechanical energy to the affected EGU or 

auxiliary equipment in MWh. 

(Pe)A = Electric energy used for any auxiliary 

loads in MWh. 

(Pt)PS = Useful thermal output of steam 

(measured relative to SATP conditions as 

defined in § 62.16375, as applicable) that 

is used for applications that do not 

generate additional electricity, produce 

mechanical energy output, or enhance 

the performance of the affected EGU. 

This is calculated using the equation 

specified in paragraph (a)(6)(i)(B) of this 

section in MWh. 

(Pt)HR = Non steam useful thermal output 

(measured relative to SATP conditions as 

defined in § 62.16375, as applicable) 

from heat recovery that is used for 

applications other than steam generation 

or performance enhancement of the 

affected EGU in MWh. 

(Pt)IE = Useful thermal output (relative to 

SATP conditions as defined in 

§ 62.16375, as applicable) from any 

integrated equipment that is used for 

applications that do not generate 

additional steam, electricity, produce 

mechanical energy output, or enhance 

the performance of the affected EGU in 

MWh. 

TDF = Electric Transmission and Distribution 

Factor of 0.95 for a combined heat and 

power affected EGU where at least on an 

annual basis 20.0 percent of the total net 

energy output consists of electric or 

direct mechanical output and 20.0 

percent of the total net energy output 

consists of useful thermal output on a 

12-operating month rolling average basis, 

or 1.0 for all other affected EGUs. 

(B) If applicable to your affected EGU 

(for example, for combined heat and 

power), you must calculate (Pt)PS using 

the following equation: 

Where: 

(Pt)ps = Useful thermal output of steam 

(measured relative to SATP conditions as 

defined in § 62.16375, as applicable) that 

is used for applications that do not 

generate additional electricity, produce 

mechanical energy output, or enhance 

the performance of the affected EGU. 

Qm = Measured steam flow in kilograms (kg) 

(or pounds (lb)) for the operating hour. 

H = Enthalpy of the steam at measured 

temperature and pressure (relative to 

SATP conditions as defined in 

§ 62.16375 or the energy in the 

condensate return line, as applicable) in 

Joules per kilogram (J/kg) (or Btu/lb). 

CF = Conversion factor of 3.6 × 109 J/MWh 

or 3.413 × 106 Btu/MWh. 

(ii) [Reserved] 

(7) In accordance with § 60.13(g), if 

two or more affected EGUs 

implementing the continuous emissions 

monitoring provisions in paragraph 

(a)(1) of this section share a common 

exhaust gas stack and are subject to the 

same emissions standard, then the 

owner or operator may monitor the 

hourly CO2 mass emissions at the 

common stack in lieu of monitoring 

each EGU separately. If an owner or 

operator of an affected EGU chooses this 

option, then the hourly net electric 

output for the common stack must be 

the sum of the hourly net electric output 

of the individual affected facility and 

the operating time must be expressed as 

‘‘stack operating hours’’ (as defined in 

§ 72.2 of this chapter). 

(8) In accordance with § 60.13(g), if 

the exhaust gases from an affected EGU 

implementing the continuous emissions 

monitoring provisions in paragraph 

(a)(3) of this section are emitted to the 

atmosphere through multiple stacks (or 

if the exhaust gases are routed to a 

common stack through multiple ducts 

and you elect to monitor in the ducts), 

the hourly CO2 mass emissions and the 

‘‘stack operating time’’ (as defined in 

§ 72.2 of this chapter) at each stack or 

duct must be monitored separately. In 

this case, the owner or operator of an 

affected EGU must determine 

compliance with an applicable 

emissions standard by summing the CO2

mass emissions measured at the 

individual stacks or ducts and dividing 

by the net energy output for the affected 

EGU. 


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(b) [Reserved] 

§ 62.16350 May I bank CO2 annual 

allowances for future use or transfer? 

(a) A CO2 allowance may be banked 

for future use or transfer in a 

compliance account or a general 

account in accordance with paragraph 

(b) of this section. 

(b) Any CO2 allowance that is held in 

a compliance account or a general 

account will remain in such account 

unless and until the CO2 allowance is 

deducted or transferred under 

§§ 62.16240(b), 62.16335, 62.16340, 

62.16355, or 62.16370. 

§ 62.16355 How does the Administrator 

process account errors? 

The Administrator may, at his or her 

sole discretion and on his or her own 

motion, correct any error in any ATCS 

account. Within 10 business days of 

making such correction, the 

Administrator will notify the authorized 

account representative for the account. 

§ 62.16360 What are my reporting, 

notification and submission requirements? 

(a) You must prepare and submit 

reports according to paragraphs (a) 

through (e) of this section, as applicable. 

(1) You must meet all applicable 

reporting requirements and submit 

reports as required under subpart G of 

part 75 of this chapter and you must 

include the following information, as 

applicable in the quarterly reports: 

(i) The hourly CO2 mass emission rate 

value (tons/hr) and unit (or stack) 

operating time, as monitored and 

reported according to part 75 of this 

chapter, for each unit or stack operating 

hour in the compliance period; 

(ii) The calculated CO2 mass 

emissions (tons) for each unit or stack 

operating hour in the compliance 

period; 

(iii) The sum of the CO2 mass 

emissions (tons) for all of the unit or 

stack operating hours in the compliance 

period; 

(iv) The net electric output and the 

net energy output (Pnet) values for each 

unit or stack operating hour in the 

compliance period; 

(v) The sum of the hourly net energy 

output values for all of the unit or stack 

operating hours in the compliance 

period; and 

(vi) If the report covers the final 

quarter of a compliance period, then 

you must include the CO2 emission 

standard with which your affected EGU 

must comply, the affected EGU’s 

calculated emission performance as a 

cumulative mass in units of the 

emission standard required, and if an 

affected EGU is complying with an 

emission standard by using allowances, 

then the designated representative must 

include in their report a list of all 

unique allowance serial numbers retired 

in the compliance period, and, for each 

allowance, the date an allowance was 

surrendered and retired. If set-aside 

allowances were used from an eligible 

resource by an affected EGU to comply 

with its emission standard, then the 

designated representative must include 

in their report the eligible resource 

identification information sufficient to 

demonstrate that it meets the 

requirements of § 62.16245 and qualifies 

to be issued allowance set-asides 

(including location, type of qualifying 

generation or savings, date commenced 

generating or saving, and date of 

generation or savings for which the 

allowance was issued). 

(2) [Reserved] 

(b) The designated representative of 

each affected EGU at the facility must 

make all submissions required under 

the CO2 Mass-based Trading Program, 

except as provided in § 62.16315. This 

requirement does not change, create an 

exemption from, or otherwise affect the 

responsible official submission 

requirements under a title V operating 

permit program in parts 70 and 71 of 

this chapter. 

(c) You must submit all electronic 

reports required under paragraph (a) of 

this section using the Emissions 

Collection and Monitoring Plan System 

(ECMPS) Client Tool provided by the 

Clean Air Markets Division in the Office 

of Atmospheric Programs of EPA. 

(d) For affected EGUs under this 

subpart that are not in the Acid Rain 

Program, you must also meet the 

reporting requirements and submit 

reports as required under subpart G of 

part 75 of this chapter, to the extent that 

those requirements and reports provide 

applicable data for the compliance 

demonstrations required under this 

subpart. 

(e) If your affected EGU captures CO2

to meet the applicable emission 

standard, then you must report in 

accordance with the requirements of 40 

CFR part 98, subpart PP, of this chapter 

and either: 

(1) Report in accordance with the 

requirements of 40 CFR part 98, subpart 

RR, of this chapter, if injection occurs 

on-site; or 

(2) Transfer the captured CO2 to an 

EGU or facility that reports in 

accordance with the requirements of 40 

CFR part 98, subpart RR, of this chapter, 

if injection occurs off site. 

(f) You must prepare and submit 

notifications specified in § 75.61 of this 

chapter, as applicable to your affected 

EGUs. 

§ 62.16365 What are my recordkeeping 

requirements? 

(a) The owner or operator of each 

affected EGU must maintain the records, 

as described in paragraphs (a)(1) and (2) 

of this section, for at least 5 years 

following the date of each compliance 

period, occurrence, measurement, 

maintenance, corrective action, report, 

or record. 

(1) The owner or operator of an 

affected EGU must maintain each record 

on site for at least 2 years after the date 

of each compliance period, compliance 

true-up period, occurrence, 

measurement, maintenance, corrective 

action, report, or record, whichever is 

latest, according to § 60.7 of this 

chapter. The owner or operator of an 

affected EGU may maintain the records 

off site and electronically for the 

remaining year(s). 

(2) The owner or operator of an 

affected EGU must keep all of the 

following records: 

(i) All emissions monitoring 

information, in accordance with this 

subpart; 

(ii) Copies of all reports, compliance 

certifications, documents, data files, 

calculations and methods, other 

submissions and all records made or 

required under, or to demonstrate 

compliance with an affected EGU’s 

emission standard under § 62.16220 and 

any other requirements of, the CO2

Mass-based Trading Program; 

(iii) Data that is required to be 

recorded by 40 CFR part 75, subpart F, 

of this chapter; and 

(iv) Data with respect to any 

allowances used by the affected EGU in 

its compliance demonstration including 

the information in paragraphs 

(a)(2)(iv)(A) and (B) of this section. 

(A) All documents related to any setaside allowances used in a compliance 

demonstration, including each 

eligibility application, EM&V plan, M&V 

report, and independent verifier 

verification report associated with the 

issuance of each specific set-aside 

allowance, and each regulatory approval 

and any documentation that supports 

the issuance of each set-aside allowance 

by the Administrator. 

(B) All records and reports relating to 

the surrender and retirement of 

allowances for compliance with this 

regulation, including the date each 

individual allowance with a unique 

serial identification number was 

surrendered and/or retired. 

(b) [Reserved] 

§ 62.16370 What actions may the 

Administrator take on submissions? 

(a) The Administrator may review and 

conduct independent audits concerning 

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any submission under the CO2 Massbased Trading Program and make 

appropriate adjustments of the 

information in the submission. 

(b) The Administrator may deduct 

CO2 allowances from or transfer CO2

allowances to a compliance account, 

based on the information in a 

submission, as adjusted under 

paragraph (a) of this section, and record 

such deductions and transfers. 

Definitions 

§ 62.16375 What definitions apply to this 

subpart? 

The terms used in this subpart have 

the meanings set forth in this section as 

follows: 

Acid Rain Program means a multistate SO2 and NOX air pollution control 

and emission reduction program 

established by the Administrator under 

title IV of the Clean Air Act and parts 

72 through 78 of this chapter. 

Administrator means the 

Administrator of the United States 

Environmental Protection Agency or his 

or her delegate, or the authorized state 

official under an approved state plan 

that incorporates this subpart. 

Affected electric generating unit or 

Affected EGU means any steam 

generating unit, IGCC, or stationary 

combustion turbine that meets the 

applicability requirements in 

§§ 60.5840(b) and 60.5845 of this 

chapter. An affected EGU is not an 

eligible resource. 

Allocate or allocation means, with 

regard to CO2 allowances, the 

determination by the Administrator, 

State, or permitting authority, in 

accordance with this subpart or any 

state allowance-distribution 

methodology submitted by the State and 

approved by the Administrator under 

§ 62.16245, to: 

(1) An affected EGU; 

(2) A renewable energy set-aside; 

(3) An output-based set-aside; or 

(4) Any other entity specified by the 

Administrator. 

Allowable CO2 emission rate means, 

for an affected EGU, the most stringent 

state or federal CO2 emission rate limit 

(in lb/MWh or, if in lb/mmBtu, 

converted to lb/MWh by multiplying it 

by the affected EGU’s heat rate in 

mmBtu/MWh) that is applicable to the 

affected EGU and covers the longest 

averaging period not exceeding 1 year. 

Allowance system means a control 

program under which the owner or 

operator of each affected EGU is 

required to hold an authorization for 

each specified unit of carbon dioxide 

emitted from that facility during a 

specified period and which limits the 

total amount of such authorizations 

available to be held for carbon dioxide 

for a specified period and allows the 

transfer of such authorizations not used 

to meet the authorization-holding 

requirement. 

Allowance Tracking and Compliance 

System (ATCS) means the system by 

which the Administrator records 

allocations, deductions, and transfers of 

CO2 allowances under the CO2 Massbased Trading Program. Such 

allowances are allocated, recorded, 

held, deducted, or transferred only as 

whole allowances. 

Allowance transfer deadline means, 

for a compliance period in a given year, 

midnight of May 1 (if it is a business 

day), or midnight of the first business 

day thereafter (if May 1 is not a business 

day), immediately after such 

compliance period and is the deadline 

by which a CO2 allowance transfer must 

be submitted for recordation in a 

facility’s compliance account in order to 

be available for use in complying with 

the facility’s CO2 emission standard for 

such compliance period in accordance 

with §§ 62.16220 and 62.16340. 

Alternate designated representative 

means, for a CO2 Mass-based Trading 

Program facility and each affected EGU 

at the facility, the natural person who is 

authorized by the owners and operators 

of the facility and all such affected 

EGUs at the facility, in accordance with 

this subpart, to act on behalf of the 

designated representative in matters 

pertaining to the CO2 Mass-based 

Trading Program. If the facility is also 

subject to the Acid Rain Program, TR 

NOX Annual Trading Program, TR NOX

Ozone Season Trading Program, TR SO2

Group 1 Trading Program, or TR SO2

Group 2 Trading Program, then this 

natural person shall be the same natural 

person as the alternate designated 

representative, as defined in the 

respective program. 

Annual capacity factor means the 

ratio between the actual heat input to an 

affected EGU during a calendar year and 

the potential heat input to the affected 

EGU had it been operated for 8,760 

hours during a calendar year at the base 

load rating. Also see capacity factor. 

Authorized account representative 

means, for a general account, the natural 

person who is authorized, in accordance 

with this subpart, to transfer and 

otherwise dispose of CO2 allowances 

held in the general account and, for a 

CO2 Mass-based Trading facility’s 

compliance account, the designated 

representative of the facility is the 

authorized account representative. 

Automated data acquisition and 

handling system (DAHS) means the 

component of the continuous emission 

monitoring system, or other emissions 

monitoring system approved for use 

under this subpart, designed to interpret 

and convert individual output signals 

from pollutant concentration monitors, 

flow monitors, diluent gas monitors, 

and other component parts of the 

monitoring system to produce a 

continuous record of the measured 

parameters in the measurement units 

required by this subpart. 

Base load rating means the maximum 

amount of heat input (fuel) that an EGU 

can combust on a steady state basis, as 

determined by the physical design and 

characteristics of the EGU at ISO 

conditions. For a stationary combustion 

turbine, base load rating includes the 

heat input from duct burners. 

Baseline means the electricity use that 

would have occurred without 

implementation of a specific EE 

measure. 

Biomass means biologically based 

material that is living or dead (e.g., 

trees, crops, grasses, tree litter, roots) 

above and below ground, and available 

on a renewable or recurring basis. 

Materials that are biologically based 

include non-fossilized, biodegradable 

organic material originating from 

modern or contemporarily grown plants, 

animals, or microorganisms (including 

plants, products, byproducts and 

residues from agriculture, forestry, and 

related activities and industries, as well 

as the non-fossilized and biodegradable 

organic fractions of industrial and 

municipal wastes, including gases and 

liquids recovered from the 

decomposition of non-fossilized and 

biodegradable organic material). 

Boiler means an enclosed fossil- or 

other-fuel-fired combustion device used 

to produce heat and to transfer heat to 

recirculating water, steam, or other 

medium. 

Business day means a day that does 

not fall on a weekend or a federal 

holiday. 

Capacity factor means, as used for the 

output based set-aside, the ratio of the 

net electrical energy produced by a 

generating unit for the period of time 

considered to the electrical energy that 

could have been produced at 

continuous net summer capacity during 

the same period. 

Certifying official means a natural 

person who is: 

(1) For a corporation, a president, 

secretary, treasurer, or vice-president of 

the corporation in charge of a principal 

business function or any other person 

who performs similar policy- or 

decision-making functions for the 

corporation; 

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(2) For a partnership or sole 

proprietorship, a general partner or the 

proprietor respectively; or 

(3) For a local government entity or 

state, federal, or other public agency, a 

principal executive officer or ranking 

elected official. 

Clean Air Act means the Clean Air 

Act, 42 U.S.C. 7401, et seq. 

CO2 allowance means a limited 

authorization issued and allocated by 

the Administrator under this subpart, or 

by a State or permitting authority under 

a state allowance-distribution 

methodology approved by the 

Administrator under § 60.24(x) of this 

chapter, to emit one ton of CO2 during 

a compliance period of the specified 

calendar year for which the 

authorization is allocated or of any 

calendar year thereafter under the CO2

Mass-Based Trading Program. 

CO2 allowance deduction or deduct 

CO2 allowances means the permanent 

withdrawal of CO2 allowances by the 

Administrator from a compliance 

account (e.g., in order to account for 

compliance with the CO2 emission 

standard). 

CO2 allowances held or hold CO2

allowances means the CO2 allowances 

treated as included in an Allowance 

Tracking and Compliance System 

(ATCS) account as of a specified point 

in time because at that time they: 

(1) Have been recorded by the 

Administrator in the account or 

transferred into the account by a 

correctly submitted, but not yet 

recorded, CO2 allowance transfer in 

accordance with this subpart; and 

(2) Have not been transferred out of 

the account by a correctly submitted, 

but not yet recorded, CO2 allowance 

transfer in accordance with this subpart. 

CO2 emission goal means a statewide 

rate-based CO2 emission goal or massbased CO2 emission goal specified in 

§ 62.16235. 

CO2 emissions limitation means the 

tonnage of CO2 emissions authorized in 

a compliance period in a given year by 

the CO2 allowances available for 

deduction for the facility under 

§ 62.16340(a) for such compliance 

period. 

CO2 Mass-Based Trading Program 

means a multi-state CO2 air pollution 

control and emission reduction program 

established in accordance with this 

subpart and subpart UUUU of part 60 of 

this chapter (including such a program 

that is revised in a State plan or state 

allowance distribution methodology, or 

by the Administrator under subpart 

UUUU of part 60 of this chapter), as a 

means of controlling CO2 emissions. 

Coal means the definition as defined 

in subpart TTTT of part 60 of this 

chapter. 

Combined cycle unit means an 

electric generating unit that uses a 

stationary combustion turbine from 

which the heat from the turbine exhaust 

gases is recovered by a heat recovery 

steam generating unit to generate 

additional electricity. 

Combined heat and power unit or 

CHP unit, (also known as 

‘‘cogeneration’’) means an electric 

generating unit that uses a steamgenerating unit or stationary combustion 

turbine to simultaneously produce both 

electric (or mechanical) and useful 

thermal output from the same primary 

energy facility. 

Common practice baseline (CPB) 

means a baseline derived based on a 

default technology or condition that 

would have been in place at the time of 

implementation of an EE measure in the 

absence of the EE measure (for example, 

the standard or market-average or preexisting equipment that a typical 

consumer/building owner would have 

continued to use or would have 

installed at the time of project 

implementation in a given 

circumstance, such as a given building 

type, EE program type or delivery 

mechanism, and geographic region). 

Common stack means a single flue 

through which emissions from two or 

more units are exhausted. 

Compliance account means an ATCS 

account, established by the 

Administrator for a CO2 annual facility 

under this subpart, in which any CO2

allowance allocations to the affected 

EGUs at the facility are recorded and in 

which are held any CO2 allowances 

available for use for a compliance 

period in a given year in complying 

with the facility’s CO2 emission 

standard in accordance with 

§§ 62.16220 and 62.16340. 

Compliance period means the multiyear periods starting January 1 of the 

first calendar year of the period, except 

as provided in § 62.16220(c)(3), and 

ending on December 31 of the last 

calendar year, inclusive: 

(1) Compliance Period 1 means the 

period of 3 calendar years from January 

1, 2022 to December 31, 2024. 

(2) Compliance Period 2 means the 

period of 3 calendar years from January 

1, 2025 to December 31, 2027. 

(3) Compliance Period 3 means the 

period of 2 calendar years from January 

1, 2028 to December 31, 2029. 

Conservation voltage regulation (or 

reduction) (CVR) means an EE measure 

that produces electricity savings by 

reducing (or regulating) voltage at the 

electrical feeder level. 

Continuous emission monitoring 

system (CEMS) means the equipment 

required under this subpart to sample, 

analyze, measure, and provide, by 

means of readings recorded at least once 

every 15 minutes and using an 

automated data acquisition and 

handling system (DAHS), a permanent 

record of CO2 emissions, stack gas 

volumetric flow rate, stack gas moisture 

content, and O2 concentration (as 

applicable), in a manner consistent with 

part 75 of this chapter and § 62.16345. 

The following systems are the principal 

types of continuous emission 

monitoring systems: 

(1) A flow monitoring system, 

consisting of a stack flow rate monitor 

and an automated data acquisition and 

handling system and providing a 

permanent, continuous record of stack 

gas volumetric flow; 

(2) A moisture monitoring system, as 

defined in § 75.11(b)(2) of this chapter 

and providing a permanent, continuous 

record of the stack gas moisture content, 

in percent H2O; 

(3) A CO2 monitoring system, 

consisting of a CO2 pollutant 

concentration monitor (or an O2 monitor 

plus suitable mathematical equations 

from which the CO2 concentration is 

derived) and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of CO2 emissions, in percent CO2; 

and 

(4) An O2 monitoring system, 

consisting of an O2 concentration 

monitor and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of O2, in percent O2. 

Control area operator means an 

electric system or systems, bounded by 

interconnection metering and telemetry, 

capable of controlling generation to 

maintain its interchange schedule with 

other control areas and contributing to 

frequency regulation of the 

interconnection. 

Deemed savings means estimates of 

average annual electricity savings for a 

single unit of an installed demand-side 

EE measure that: Has been developed 

from data sources (such as prior 

metering studies) and analytical 

methods widely considered acceptable 

for the measure; and is applicable to the 

situation and conditions in which the 

measure is implemented. Individual 

parameters or calculation methods also 

can be deemed, including EUL values. 

Common sources of deemed savings 

values are previous evaluations and 

studies that involved actual 

measurements and analyses. Deemed 

savings values are applicable for 

specific demand-side EE measures. A 

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single deemed savings value may not be 

used for a program as a whole, nor for 

a multi-measure project, because of the 

degree of variation in how systems are 

used in different building types or 

market segments. 

Demand-side energy efficiency or 

demand-side EE means energy 

efficiency activities, projects, programs 

or measures resulting in electricity 

savings. 

Derate means a decrease in the 

available capacity of an electric 

generating unit, due to a system or 

equipment modification or to 

discounting a portion of a generating 

unit’s capacity for planning purposes. 

Designated representative means, for 

a CO2 Mass-based Trading facility and 

each affected EGU at the facility, the 

natural person who is authorized by the 

owners and operators of the facility and 

all such affected EGUs at the facility, in 

accordance with this subpart, to 

represent and legally bind each owner 

and operator in matters pertaining to the 

CO2 Mass-based Trading Program. If the 

CO2 Mass-based Trading facility is also 

subject to the Acid Rain Program, TR 

NOX Annual Trading Program, TR NOX

Ozone Season Trading Program, TR SO2

Group 1 Trading Program, or TR SO2

Group 2 Trading Program, then this 

natural person shall be the same natural 

person as the designated representative, 

as defined in the respective program. 

Design efficiency means the rated 

overall net efficiency (e.g., electric plus 

thermal output) on a higher heating 

value basis of the EGU at the base load 

rating and ISO conditions. 

Distillate oil means the definition as 

defined in subpart TTTT of part 60 of 

this chapter. 

Effective useful life (EUL) means the 

duration over which electricity savings 

from an EE measure occur, reported in 

years. EUL values are typically specific 

to individual EE projects but also may 

be specified by EE program. 

Energy efficiency measure or EE 

measure means a single technology, 

energy-use practice or behavior that, 

once implemented or adopted, reduces 

electricity use of a particular end-use, 

facility, or premises; EE measures may 

be implemented as part of an EE 

program or as an independent privatelyfunded action. 

Energy efficiency program or EE 

program means organized activities 

sponsored and funded by a particular 

entity to promote the adoption of one or 

more EE project or EE measure for the 

purpose of reducing electricity use. 

Energy efficiency project or EE project 

means a combination of multiple 

technologies, energy-use practices or 

behaviors implemented at a single 

facility or premises for the purpose of 

reducing electricity use; EE projects may 

be implemented as part of an EE 

program or as an independent privatelyfunded action. 

Electricity savings means the savings 

that results from a change in electricity 

use resulting from the implementation 

of an EE measure. 

Eligible resource means a resource 

that meets the requirements of 

§ 62.16245 and has been registered with 

the EPA-administered ATCS or an 

allowance tracking system approved in 

a State plan by the EPA. An eligible 

resource is not an affected EGU. 

EM&V plan means an evaluation 

measurement and verification plan that 

meets the requirements of § 62.16260. 

Emissions means air pollutants 

exhausted from an affected EGU or 

facility into the atmosphere; emissions 

must be measured, recorded, and 

reported to the Administrator by the 

designated representative, and as 

modified by the Administrator: 

(1) In accordance with this subpart; 

and 

(2) With regard to a period before the 

affected EGU or facility is required to 

measure, record, and report such air 

pollutants in accordance with this 

subpart, and in accordance with part 75 

of this chapter. 

Emission rate credit (ERC) means a 

tradable compliance instrument that 

meets the requirements of § 60.5790(c) 

of this chapter. 

Energy service company means a 

private enterprise engaged in delivering 

electricity savings directly for an enduse customer or as an agent of a 

sponsoring entity such as a utility. 

Essential generating characteristics 

means any characteristic that affects the 

eligibility of the qualifying energy 

generating facility for generating 

allowances pursuant to this regulation, 

including the type of facility. 

Excess emissions means any ton of 

emissions from the affected EGUs at a 

facility during a compliance period that 

exceeds the CO2 emissions limitation for 

the facility for such compliance period. 

Existing state program, requirement, 

or measure means, in the context of a 

State plan, a regulation, requirement, 

program, or measure administered by a 

state, utility, or other entity that is 

currently established. This may include 

a regulation or other legal requirement 

that includes past, current, and future 

obligations, or current programs and 

measures that are in place and are 

anticipated to be continued or expanded 

in the future, in accordance with 

established plans. An existing state 

program, requirement, or measure may 

have past, current, and future impacts 

on EGU CO2 emissions. 

Facility means all buildings, 

structures, or installations located in 

one or more contiguous or adjacent 

properties under common control of the 

same person or persons. This definition 

does not change or otherwise affect the 

definition of ‘‘major source’’, ‘‘stationary 

source’’, or ‘‘source’’ as set forth and 

implemented in a title V operating 

permit program or any other program 

under the Clean Air Act. 

Final compliance period means a 

compliance period within the final 

period, each being 2 calendar years 

(with a calendar year beginning on 

January 1 and ending on December 31), 

and the first final compliance period 

beginning on January 1, 2030 and 

ending December 31, 2031. 

Final period means the period that 

begins on January 1, 2030 and continues 

thereafter. The final period is comprised 

of final compliance periods, each of 

which is 2 calendar years (with a 

calendar year beginning on January 1 

and ending on December 31). 

Fossil fuel means the definition as 

defined in subpart TTTT of part 60 of 

this chapter. 

Fossil-fuel-fired means, with regard to 

an affected EGU, combusting any 

amount of fossil fuel. 

Gaseous fuel means the definition as 

defined in subpart TTTT of part 60 of 

this chapter. 

General account means an ATCS 

account established under this subpart 

that is not a compliance account. 

Generation period means the 

compliance period from which the 

Administrator uses operations data of 

affected EGUs to calculate allowances 

from the output-based allocation setaside for the following compliance 

period. 

Generation year means a calendar 

year for which a renewable energy 

project submits its projected generation 

to the Administrator by June 1 of the 

preceding year for allowances from the 

renewable energy set-aside. 

Generator means a device that 

produces electricity. 

Gross electrical output means, for an 

affected EGU, electricity made available 

for use, including any such electricity 

used in the power production process 

(which process includes, but is not 

limited to, any on-site processing or 

treatment of fuel combusted at the 

affected EGU and any on-site emission 

controls). 

Heat input means, for an affected EGU 

for a specified period of time, the 

product (in mmBtu/time) of the gross 

calorific value of the fuel (in mmBtu/lb) 

fed into the affected EGU multiplied by 

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the fuel feed rate (in lb of fuel/time), as 

measured, recorded, and reported to the 

Administrator by the designated 

representative and as modified by the 

Administrator in accordance with this 

subpart and excluding the heat derived 

from preheated combustion air, 

recirculated flue gases, or exhaust. 

Heat input rate means, for an affected 

EGU, the amount of heat input (in 

mmBtu) divided by affected EGU 

operating time (in hr) or, for an affected 

EGU and a specific fuel, the amount of 

heat input attributed to the fuel (in 

mmBtu) divided by the affected EGU 

operating time (in hr) during which the 

affected EGU combusts the fuel. 

Heat rate means, for an affected EGU, 

the affected EGU’s maximum design 

heat input (in Btu/hr), divided by the 

product of 1,000,000 Btu/mmBtu and 

the affected EGU’s maximum hourly 

load. 

Heat recovery steam generating unit 

(HRSG) means a unit in which hot 

exhaust gases from the combustion 

turbine engine are routed in order to 

extract heat from the gases and generate 

useful output. Heat recovery steam 

generating units can be used with or 

without duct burners. 

Indian country means ‘‘Indian 

country’’ as defined in 18 U.S.C. 1151. 

Integrated gasification combined 

cycle facility or IGCC facility means a 

combined cycle facility that is designed 

to burn fuels containing 50 percent (by 

heat input) or more solid-derived fuel 

not meeting the definition of natural gas 

plus any integrated equipment that 

provides electricity or useful thermal 

output to either the affected facility or 

auxiliary equipment. The Administrator 

may waive the 50 percent solid-derived 

fuel requirement during periods of the 

gasification system construction, startup 

and commissioning, shutdown, or 

repair. No solid fuel is directly burned 

in the unit during operation. 

Interim period means the period of 8 

calendar years from January 1, 2022 to 

December 31, 2029. The interim period 

is comprised of three compliance 

periods, compliance period 1, 

compliance period 2, and compliance 

period 3. 

ISO conditions means 288 Kelvin (15° 

C), 60 percent relative humidity and 

101.3 kilopascals pressure. 

Liquid fuel means the definition as 

defined in subpart TTTT of part 60 of 

this chapter. 

M&V report means a monitoring and 

verification report that meets the 

requirements of § 62.16265. 

Maximum design heat input means, 

for an affected EGU, the maximum 

amount of fuel per hour (in Btu/hr) that 

the affected EGU is capable of 

combusting on a steady state basis as of 

the initial installation of the affected 

EGU as specified by the manufacturer of 

the affected EGU. 

Mechanical output means the useful 

mechanical energy that is not used to 

operate the affected facility, generate 

electricity and/or thermal output, or to 

enhance the performance of the affected 

facility. Mechanical energy measured in 

horsepower hour should be converted 

into MWh by multiplying it by 745.7 

then dividing by 1,000,000. 

Monitoring system means any 

monitoring system that meets the 

requirements of this subpart, including 

a continuous emission monitoring 

system, an alternative monitoring 

system, or an excepted monitoring 

system under part 75 of this chapter. 

Nameplate capacity means, starting 

from the initial installation of a 

generator, the maximum electrical 

generating output (in MWe, rounded to 

the nearest tenth) that the generator is 

capable of producing on a steady state 

basis and during continuous operation 

(when not restricted by seasonal or 

other deratings) of such installation as 

specified by the manufacturer of the 

generator or, starting from the 

completion of any subsequent physical 

change in the generator resulting in an 

increase in the maximum electrical 

generating output that the generator is 

capable of producing on a steady state 

basis and during continuous operation 

(when not restricted by seasonal or 

other deratings), such increased 

maximum amount (in MWe, rounded to 

the nearest tenth) of such completion as 

specified by the person conducting the 

physical change. 

Natural gas means the definition as 

defined in subpart TTTT of part 60 of 

this chapter. 

Net-electric output means the amount 

of gross generation the generator(s) 

produce (including, but not limited to, 

output from steam turbine(s), 

combustion turbine(s), and gas 

expander(s)), as measured at the 

generator terminals, less the electricity 

used to operate the plant (i.e., auxiliary 

loads); such uses include fuel handling 

equipment, pumps, fans, pollution 

control equipment, other electricity 

needs, and transformer losses as 

measured at the transmission side of the 

step up transformer (e.g., the point of 

sale). 

Net energy output means: 

(1) The net electric or mechanical 

output from the affected facility, plus 

100 percent of the useful thermal output 

measured relative to SATP conditions 

that is not used to generate additional 

electric or mechanical output or to 

enhance the performance of the affected 

EGU (e.g., steam delivered to an 

industrial process for a heating 

application); and 

(2) For combined heat and power 

facilities where at least 20.0 percent of 

the total gross or net energy output 

consists of electric or direct mechanical 

output and at least 20.0 percent of the 

total gross or net energy output consists 

of useful thermal output on a 12- 

operating month rolling average basis, 

the net electric or mechanical output 

from the affected EGU divided by 0.95, 

plus 100 percent of the useful thermal 

output (e.g., steam delivered to an 

industrial process for a heating 

application). 

Net summer capacity means the 

maximum output, commonly expressed 

in megawatts (MW), that generating 

equipment can supply to system load, as 

demonstrated by a multi-hour test, at 

the time of summer peak demand 

(period of June 1 through September 

30.) This output reflects a reduction in 

capacity due to electricity use for station 

service or auxiliaries. 

Operate or operation means, with 

regard to an affected EGU, to combust 

fuel. 

Operator means, for a CO2 Mass-based 

Trading facility or an affected EGU at a 

facility respectively, any person who 

operates, controls, or supervises an 

affected EGU at the facility or the 

affected EGU and includes, but is not 

limited to, any holding company, utility 

system, or plant manager of such facility 

or affected EGU. 

Owner means, for a CO2 Mass-based 

Trading facility or an affected EGU at a 

facility respectively, any of the 

following persons: 

(1) Any holder of any portion of the 

legal or equitable title in an affected 

EGU at the facility or the affected EGU; 

(2) Any holder of a leasehold interest 

in an affected EGU at the facility or the 

affected EGU, provided that, unless 

expressly provided for in a leasehold 

agreement, ‘‘owner’’ does not include a 

passive lessor, or a person who has an 

equitable interest through such lessor, 

whose rental payments are not based 

(either directly or indirectly) on the 

revenues or income from such affected 

EGU; and 

(3) Any purchaser of power from an 

affected EGU at the facility or the 

affected EGU under a life-of-the-unit, 

firm power contractual arrangement. 

Permanently retired means, with 

regard to an affected EGU, that an 

affected EGU is unavailable for service 

and the affected EGU’s owners and 

operators: have taken on as enforceable 

obligations in the operating permit that 

covers the affected EGU the conditions 

of § 62.16215; or rescinded or otherwise 

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terminated all permits required for 

construction or operation of the affected 

EGU under the Clean Air Act. 

Cessations in operations that do not 

meet this definition do not constitute 

permanent retirements. 

Qualified biomass means a biomass 

feedstock that is demonstrated as a 

method to control increases of CO2

levels in the atmosphere. 

Random error means errors occurring 

by chance that may cause electricity 

savings values to be inconsistently 

overestimated or underestimated, and 

may result from a change in electricity 

use due to unaccounted-for factors that 

affect electricity use. The magnitude of 

random error can be quantified based on 

the variations observed across different 

units. 

Receive or receipt of means, when 

referring to the Administrator, to come 

into possession of a document, 

information, or correspondence 

(whether sent in hard copy or by 

authorized electronic transmission), as 

indicated in an official log, or by a 

notation made on the document, 

information, or correspondence, by the 

Administrator in the regular course of 

business. 

Recordation, record, or recorded 

means, with regard to CO2 allowances, 

the moving of CO2 allowances by the 

Administrator into, out of, or between 

ATCS accounts, for purposes of 

allocation, transfer, or deduction. 

Reference method means any direct 

test method of sampling and analyzing 

for an air pollutant as specified in 

§ 75.22 of this chapter. 

Replacement, replace, or replaced 

means, with regard to an affected EGU, 

the demolishing of an affected EGU, or 

the permanent retirement and 

permanent disabling of an affected EGU, 

and the construction of another affected 

EGU (the replacement affected EGU) to 

be used instead of the demolished or 

retired affected EGU (the replaced 

affected EGU). 

Solid fuel means any fuel that has a 

definite shape and volume, has no 

tendency to flow or disperse under 

moderate stress, and is not liquid or 

gaseous at ISO conditions. This 

includes, but is not limited to, coal, 

biomass, and pulverized solid fuels. 

Solid waste incineration unit means a 

stationary, fossil-fuel-fired boiler or 

stationary, fossil-fuel-fired combustion 

turbine that is a ‘‘solid waste 

incineration unit’’ as defined in section 

129(g)(1) of the Clean Air Act. 

Standard ambient temperature and 

pressure (SATP) conditions means 

298.15 Kelvin (25° C, 77 °F)) and 100.0 

kilopascals (14.504 psi, 0.987 atm) 

pressure. The enthalpy of water at SATP 

conditions is 50 Btu/lb. 

State agent means an entity acting on 

behalf of the State, with the legal 

authority of the State. 

State measures means measures that 

the State adopts and implements as a 

matter of state law. Such measures are 

enforceable only per state law, and are 

not included in and codified as part of 

the federally enforceable State plan. 

Stationary combustion turbine means 

all equipment, including but not limited 

to the turbine engine, the fuel, air, 

lubrication and exhaust gas systems, 

control systems (except emissions 

control equipment), heat recovery 

system, fuel compressor, heater, and/or 

pump, post-combustion emissions 

control technology, and any ancillary 

components and sub-components 

comprising any simple cycle stationary 

combustion turbine, any combined 

cycle combustion turbine, and any 

combined heat and power combustion 

turbine based system plus any 

integrated equipment that provides 

electricity or useful thermal output to 

the combustion turbine engine, heat 

recovery system or auxiliary equipment. 

Stationary means that the combustion 

turbine is not self-propelled or intended 

to be propelled while performing its 

function. It may, however, be mounted 

on a vehicle for portability. If a 

stationary combustion turbine burns any 

solid fuel directly then it is considered 

a steam generating unit. 

Steam generating unit means any 

furnace, boiler, or other device used for 

combusting fuel and producing steam 

(nuclear steam generators are not 

included) plus any integrated 

equipment that provides electricity or 

useful thermal output to the affected 

facility or auxiliary equipment. 

Submit or serve means to send or 

transmit a document, information, or 

correspondence to the person specified 

in accordance with the applicable 

regulation: 

(1) In person; 

(2) By United States Postal Service; or 

(3) By other means of dispatch or 

transmission and delivery; 

(4) Provided that compliance with any 

‘‘submission’’ or ‘‘service’’ deadline 

shall be determined by the date of 

dispatch, transmission, or mailing and 

not the date of receipt. 

Systematic error means inaccuracies 

in the same direction, causing electricity 

savings values to be consistently either 

overestimated or underestimated, and 

may result from factors such as incorrect 

assumptions, a methodological issue, or 

a flawed reporting system. 

Transmission and distribution loss 

means the difference between the 

quantity of electricity that serves a load 

(measured at the busbar of the 

generator) and the actual electricity use 

at the final distribution location 

(measured at the on-site meter). 

Transmission and distribution 

measures or T&D measures means EE 

measures intended to improve the 

efficiency of the electrical transmission 

and distribution system by decreasing 

electricity loses on the system. 

Unit operating day means, with 

regard to an affected EGU, a calendar 

day in which the affected EGU combusts 

any fuel. 

Unit operating hour or hour of unit 

operation means, with regard to an 

affected EGU, an hour in which the 

affected EGU combusts any fuel. 

Uprate means an increase in available 

electric generating unit power capacity 

due to a system or equipment 

modification. 

Useful thermal output means the 

thermal energy made available for use in 

any heating application (e.g., steam 

delivered to an industrial process for a 

heating application, including thermal 

cooling applications) that is not used for 

electric generation, mechanical output 

at the affected EGU, to directly enhance 

the performance of the affected EGU 

(e.g., economizer output is not useful 

thermal output, but thermal energy used 

to reduce fuel moisture is considered 

useful thermal output), or to supply 

energy to a pollution control device at 

the affected EGU. Useful thermal output 

for affected EGU(s) with no condensate 

return (or other thermal energy input to 

the affected EGU(s)) or where measuring 

the energy in the condensate (or other 

thermal energy input to the affected 

EGU(s)) would not meaningfully impact 

the emission rate calculation is 

measured against the energy in the 

thermal output at SATP conditions. 

Affected EGU(s) with meaningful energy 

in the condensate return (or other 

thermal energy input to the affected 

EGU) must measure the energy in the 

condensate and subtract that energy 

relative to SATP conditions from the 

measured thermal output. 

Utility power distribution system 

means the portion of an electricity grid 

owned or operated by a utility and 

dedicated to delivering electricity to 

customers. 

Valid data means quality-assured data 

generated by continuous monitoring 

systems that are installed, operated, and 

maintained according to part 75 of this 

chapter. For CEMS, the initial 

certification requirements in § 75.20 of 

this chapter and appendix A to part 75 

of this chapter must be met before 

quality-assured data are reported under 

this subpart; for on-going quality 

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assurance, the daily, quarterly, and 

semiannual/annual test requirements in 

sections 2.1, 2.2, and 2.3 of appendix B 

to part 75 of this chapter must be met 

and the data validation criteria in 

sections 2.1.5, 2.2.3, and 2.3.2 of 

appendix B to part 75 of this chapter 

apply. For fuel flow meters, the initial 

certification requirements in section 

2.1.5 of appendix D to part 75 of this 

chapter must be met before qualityassured data are reported under this 

subpart (except for qualifying 

commercial billing meters under section 

2.1.4.2 of appendix D), and for on-going 

quality assurance, the provisions in 

section 2.1.6 of appendix D to part 75 

of this chapter apply (except for 

qualifying commercial billing meters). 

Verification report means a report that 

meets the requirements of § 62.16270. 

Waste-to-Energy means a process or 

unit (e.g., solid waste incineration unit) 

that recovers energy from the 

conversion or combustion of waste 

stream materials, such as municipal 

solid waste, to generate electricity and/ 

or heat. 

§ 62.16380 What measurements, 

abbreviations, and acronyms apply to this 

subpart? 

The measurements, abbreviations, and 

acronyms used in this subpart are 

defined as follows: 

ADR—alternated designated representative 

Btu—British thermal unit 

CO2—carbon dioxide 

COI—conflict of interest 

CPP—clean power plan 

CVR—conservation voltage regulation 

DR—designated representative 

EE—energy efficiency 

EGU—electric generating unit 

EM&V—evaluation, measurement, and 

verification 

GCV—gross calorific value 

GJ—giga joule 

H2O—water 

hr—hour 

IGCC—integrated gasification combined 

cycle 

kg—kilogram 

kW—kilowatt electrical 

kWh—kilowatt hour 

lb—pound 

M&V—measurement and verification 

mmBtu—million Btu 

MWe—megawatt electrical 

MWh—megawatt hour 

O2—oxygen 

PB–MV—project-based measurement and 

verification 

PSD—prevention of significant deterioration 

T&D—transmission and distribution 

TRM—technical reference manual 

yr—year 

■ 5. Add subpart NNN to read as 

follows: 

Subpart NNN—Greenhouse Gas 

Emissions Rate-based Model Trading 

Rule for Electric Utility Generating 

Units That Commenced Construction 

on or Before January 8, 2014 

Sec. 

Introduction 

62.16405 What is the purpose of this 

subpart? 

Applicability of This Subpart 

62.16410 Am I subject to this subpart? 

62.16415 What are the requirements for 

retired affected EGUs? 

General Requirements 

62.16420 What emission standards and 

requirements must I comply with? 

62.16425 How should I compute time under 

the CO2 Rate-based Trading Program? 

62.16430 What are the administrative 

appeal procedures? 

62.16431 How will the Clean Energy 

Incentive Program be administered 

under the federal plan? 

Emission Rate Credit Issuance, Adjustment, 

and Revocation 

62.16434 What affected EGUs qualify for 

generation of ERCs? 

62.16435 What eligible resources qualify for 

generation of ERCs in addition to 

affected EGUs? 

62.16440 What is the process for revocation 

of qualification status of an eligible 

resource? 

62.16445 What is the process for the 

issuance of ERCs? 

62.16450 What is the process for error 

adjustments or misstatement, and 

suspension of ERC issuance? 

Evaluation Measurement and Verification 

Plans, Monitoring and Verification Reports, 

and Verification 

62.16455 What are the requirements for 

evaluation measurement and verification 

plans for eligible resources? 

62.16460 What are the requirements for 

monitoring and verification reports for 

eligible resources? 

62.16465 What are the requirements for 

verification reports? 

62.16470 What is the accreditation 

procedure for independent verifiers? 

62.16475 What are the procedures of 

accredited independent verifiers must 

follow to avoid conflict of interest? 

62.16480 What is the process for the 

revocation of accreditation status for an 

independent verifier? 

Designated Representatives 

62.16485 How are designated 

representatives and alternate designated 

representatives authorized and what role 

do authorized designated representatives 

and alternate designated representatives 

play? 

62.16490 What responsibilities do 

designated representatives and alternate 

designated representatives hold? 

62.16495 What are the processes for 

changing designated representatives, 

alternate designated representatives, 

owners and operators, and affected 

EGUs? 

62.16500 What must be included in a 

certificate of representation? 

62.16505 What is the Administrator’s role 

in objections concerning designated 

representatives and alternate designated 

representatives? 

62.16510 What process must designated 

representatives and alternate designated 

representatives follow to delegate their 

authority? 

Monitoring, Recordkeeping, Reporting 

62.16515 How are compliance accounts and 

general accounts established and used, 

and how is ERC issuance documentation 

accessed? 

62.16525 How must transfers of ERCs be 

submitted? 

62.16530 When will ERC transfers be 

recorded? 

62.16535 How will deductions for 

compliance with a CO2 emission 

standard occur? 

62.16540 What monitoring requirements 

must I comply with? 

62.16545 May I bank CO2 ERCs for future 

use or transfer? 

62.16550 How does the Administrator 

process account errors? 

62.16555 What are my reporting, 

notification and submission 

requirements? 

62.16560 What are my recordkeeping 

requirements? 

62.16565 What actions may the 

Administrator take on submissions? 

Definitions 

62.16570 What definitions apply to this 

subpart? 

62.16575 What measurements, 

abbreviations, and acronyms apply to 

this subpart? 

Table 1 to Subpart NNN of Part 62—CO2

Emission Standards (Pounds of CO2 Per 

Net MWh) 

Table 2 to Subpart NNN of Part 62— 

Incremental Generation Factor for 

Emission Rate Credits 

Subpart NNN—Greenhouse Gas 

Emissions Rate-Based Model Trading 

Rule for Electric Utility Generating 

Units That Commenced Construction 

on or Before January 8, 2014 

Introduction 

§ 62.16405 What is the purpose of this 

subpart? 

(a) This subpart sets forth the 

requirements for the Clean Power Plan 

(CPP) CO2 Rate-based Trading Program, 

under section 111 of the Clean Air Act 

and subpart UUUU of part 60 of this 

chapter, as a means of meeting emission 

guidelines limiting greenhouse gas 

emissions from an affected steam 

generating unit, integrated gasification 

combined cycle (IGCC), or stationary 

combustion turbine. 

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(b) The pollutants regulated by this 

subpart are greenhouse gases. The 

greenhouse gas limitations in this 

subpart are in the form of an emission 

standard for carbon dioxide (CO2). 

(c) PSD and Title V thresholds for 

greenhouse gases. (1) For the purposes 

of § 51.166(b)(49)(ii) of this chapter, 

with respect to GHG emissions from 

affected facilities, the ‘‘pollutant that is 

subject to the standard promulgated 

under section 111 of the Act’’ shall be 

considered to be the pollutant that 

otherwise is subject to regulation under 

the Act as defined in § 51.166(b)(48) of 

this chapter and in any state 

implementation plan approved by the 

EPA that is interpreted to incorporate, 

or specifically incorporates, 

§ 51.166(b)(48) of this chapter. 

(2) For the purposes of 

§ 52.21(b)(50)(ii) of this chapter, with 

respect to GHG emissions from affected 

facilities, the ‘‘pollutant that is subject 

to the standard promulgated under 

section 111 of the Act’’ shall be 

considered to be the pollutant that 

otherwise is subject to regulation under 

the Act as defined in § 52.21(b)(49) of 

this chapter. 

(3) For the purposes of § 70.2 of this 

chapter, with respect to greenhouse gas 

emissions from affected facilities, the 

‘‘pollutant that is subject to any 

standard promulgated under section 111 

of the Act’’ shall be considered to be the 

pollutant that otherwise is ‘‘subject to 

regulation’’ as defined in § 70.2 of this 

chapter. 

(4) For the purposes of § 71.2 of this 

chapter, with respect to greenhouse gas 

emissions from affected facilities, the 

‘‘pollutant that is subject to any 

standard promulgated under section 111 

of the Act’’ shall be considered to be the 

pollutant that otherwise is ‘‘subject to 

regulation’’ as defined in § 71.2 of this 

chapter. 

Applicability of This Subpart 

§ 62.16410 Am I subject to this subpart? 

(a) You are subject to this subpart if 

you are the owner or operator of an 

affected electric generating unit (EGU) 

located within a State that has 

incorporated by reference this subpart 

as a State plan, or portion of a State 

plan, that has been approved by the 

Administrator and is effective under 

subpart UUUU of part 60 of this chapter, 

or if this subpart is promulgated and 

effective as a federal plan in your State 

under part 62 of this chapter. 

(b) An affected EGU is any steam 

generating unit, IGCC, or stationary 

combustion turbine that meets the 

applicability requirements in 

§§ 60.5840(b) and 60.5845 of this 

chapter. 

§ 62.16415 What are the requirements for 

retired affected EGUs? 

(a) Exemption. (1) Any affected EGU 

that is permanently retired as defined in 

§ 62.16570 is exempt from 

§§ 62.16420(c)(1) [CO2 Emissions 

Requirements], 62.16535 [Compliance 

Requirements], 62.16540 [Monitoring], 

62.16555 [Reporting], and 62.16560 

[Recordkeeping]. 

(2) The exemption under paragraph 

(a)(1) of this section will become 

effective on the first day of the 

compliance period immediately 

following the compliance period in 

which the retirement took effect. Within 

30 days of the affected EGU’s permanent 

retirement, the designated 

representative must submit a statement 

to the Administrator. The statement 

must state, in a format prescribed by the 

Administrator, that the affected EGU 

was permanently retired on a specified 

date and will comply with the 

requirements of paragraph (b) of this 

section. 

(b) Special provisions. (1) An affected 

EGU exempt under paragraph (a) of this 

section must not emit any CO2, starting 

on the date that the exemption takes 

effect. 

(2) For a period of 5 years from the 

date the records are created, the owners 

and operators of an affected EGU 

exempt under paragraph (a) of this 

section must retain, at the affected EGU, 

records demonstrating that the affected 

EGU is permanently retired. The 5-year 

period for keeping records may be 

extended for cause, at any time before 

the end of the period, in writing by the 

Administrator. The owners and 

operators bear the burden of proof that 

the affected EGU is permanently retired. 

(3) The owners and operators and, to 

the extent applicable, the designated 

representative of an affected EGU 

exempt under paragraph (a) of this 

section must comply with the 

requirements of the CO2 Rate-based 

Trading Program accruing during any 

compliance periods for which the 

exemption is not in effect, even if such 

requirements must be complied with 

after the exemption takes effect. 

General Requirements 

§ 62.16420 What emission standards and 

requirements must I comply with? 

(a) Designated representative 

requirements. The owners and operators 

must have a designated representative, 

and may have an alternate designated 

representative, in accordance with 

§§ 62.16485 through 62.16495. 

(b) Emissions monitoring, reporting, 

and recordkeeping requirements. (1) 

The owners and operators, and the 

designated representative, of affected 

EGU must comply with the monitoring, 

reporting, and recordkeeping 

requirements of §§ 62.16540, 62.16555, 

and 62.16560. 

(2) The emissions data determined in 

accordance with § 62.16540 must be 

used to determine compliance with the 

CO2 emission standard under paragraph 

(c) of this section, provided that, for 

each monitoring location from which 

emissions are reported, the emission 

rate used in determining compliance 

must be the CO2 emission rate at the 

monitoring location determined in 

accordance with paragraph (c) of this 

section. 

(c) CO2 emission standard 

requirements. (1) Each designated 

representative for each affected EGU 

must demonstrate compliance with its 

emission standard listed in Table 1 of 

this subpart, as applicable, by 

calculating a CO2 emission rate by 

factoring stack emissions and any 

emission rate credits (ERCs) into the 

following equation: 

Where: 

CO2 emission rate = An affected EGU’s 

calculated CO2 emission rate that will be 

used to determine compliance with the 

applicable CO2 emission standard. 

MCO2 = Measured CO2 mass in units of 

pounds (lbs) summed over the 

compliance period for an affected EGU. 

MWhop = Total net energy output over the 

compliance period for an affected EGU 

in units of MWh. 

MWhERC = ERC replacement generation for 

an affected EGU in units of MWh (ERCs 

are denominated in whole integers as 

specified in paragraph (c)(2) of this 

section). 


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(2) An ERC qualifies for the 

compliance demonstration specified in 

paragraph (c)(1) of this section if it: 

(i) Has a unique serial number; 

(ii) Represents one whole MWh of 

actual energy generated or saved with 

zero associated carbon dioxide 

emissions; 

(iii) Was issued to an eligible resource 

that meets the requirements of 

§ 62.16435 or to an affected EGU that 

meets the requirements of § 62.16434, 

by the Administrator through an ERC 

tracking system or the ATCS; and 

(iv) Was surrendered and retired only 

once for purposes of compliance with 

this regulation by the Administrator 

through an ERC tracking system or the 

ATCS. 

(3) An ERC does not qualify for the 

compliance demonstration specified in 

paragraph (c)(1) of this section if it does 

not meet the requirements of paragraph 

(c)(2) of this section or if any State has 

used that same ERC for purposes of 

demonstrating achievement of its state 

measures. 

(4) As of the ERC transfer deadline for 

a compliance period, the owners and 

operators of each affected EGU must 

hold, in the affected EGU’s compliance 

account, sufficient ERCs to demonstrate 

compliance with its applicable emission 

standard listed in Table 1 of this subpart 

pursuant to the requirement of 

paragraph (c)(1) of this section. 

(5) If an affected EGU exceeds its 

emission standard during a compliance 

period, then: 

(i) The owners and operators of the 

affected EGU must hold ERCs required 

for deduction under § 62.16535(e); 

(ii) The owners and operators of the 

affected EGU are subject to federal 

enforcement pursuant to sections 

113(a)–(h), and section 304, of the Clean 

Air Act, and the United States, States, 

and other persons have the ability to 

enforce against violations (including if 

an affected EGU does not meet its 

emission standard based on its 

emissions, or use of ERCs that meet the 

compliance demonstration in § 62.16420 

(c)(2)) and secure appropriate corrective 

actions, and the owners and operators 

must pay any fine, penalty, or 

assessment or comply with any other 

remedy imposed, for the same 

violations, under the Clean Air Act, and 

each day of such compliance period will 

constitute a separate violation of this 

subpart and the Clean Air Act; 

(iii) If an affected EGU does not meet 

its emission standard because it did not 

meet the emissions standard based on 

its stack emissions and generation alone 

and it did not obtain sufficient 

qualifying ERCs to meet its emission 

standard by July 1 of the year following 

the relevant compliance period, then it 

may be subject to federal enforcement 

pursuant to Sections 113(a)–(h), 42 

U.S.C. 7413(a)–(h), and Section 304 of 

the Clean Air Act, 42 U.S.C. 7604, and 

the United States, states, and other 

persons have the ability to enforce 

violations and secure corrective actions; 

and 

(iv) If an affected EGU obtained 

sufficient facially valid ERCs to meet its 

emission standard, but those ERCs were 

found to be invalid, then it may be 

subject to federal enforcement as 

specified in paragraph (c)(5)(iii) of this 

section. 

(d) Compliance periods. An affected 

EGU will be subject to the requirements 

under paragraph (c)(1) of this section for 

the compliance period starting on 

January 1, 2022, and for each 

compliance period thereafter. 

(1) Vintage of ERCs held for 

compliance. An ERC held for 

compliance with the requirements 

under paragraph (c)(1) of this section for 

a compliance period must be an ERC 

that was issued for a year in such 

compliance period or for a year in a 

prior compliance period. 

(2) ATCS. Each ERC must be held in, 

deducted from, transferred into, out of, 

or between ATCS accounts in 

accordance with this subpart. 

(3) Limited authorization. (i) An ERC 

shall only be used in accordance with 

the CO2 Rate-based Trading Program; 

and 

(ii) Notwithstanding any other 

provision of this subpart, the 

Administrator has the authority to 

terminate or limit the use and duration 

of such authorization to the extent the 

Administrator determines is necessary 

or appropriate to implement any 

provision of the Clean Air Act. 

(4) Property right. An ERC does not 

constitute a property right. 

(e) Title V permit requirements. (1) 

Unless otherwise specified in this 

paragraph, all requirements of this 

subpart shall be applicable requirements 

that must be included in an affected 

EGU’s title V permit. 

(2) The applicable requirements of 

this subpart, as well as other terms or 

conditions necessary to ensure 

compliance with the applicable 

requirements, may be added to, or 

changed in, a title V permit using minor 

permit modification procedures in 

accordance with §§ 70.7(e)(2) and 

71.7(e)(1) of this chapter, provided that 

such changes do not conflict with any 

existing terms of the permit. This 

paragraph explicitly provides that the 

addition of, or change to, an affected 

EGU’s description as described in the 

prior sentence is eligible for minor 

permit modification procedures in 

accordance with §§ 70.7(e)(2)(i)(B) and 

71.7(e)(1)(i)(B) of this chapter. 

(3) No title V permit revision will be 

required for any crediting, holding, 

deduction, or transfer of ERCs in 

accordance with this subpart, provided 

that the requirements applicable to such 

creditings, holdings, deductions, or 

transfers of ERCs are already 

incorporated in such permit. 

(f) Liability. Any provision of the CO2

Rate-based Trading Program that applies 

to an affected EGU or the designated 

representative of an affected EGU shall 

also apply to the owners and operators 

of such affected EGU. 

(g) Effect on other authorities. No 

provision of the CO2 Rate-based Trading 

Program or exemption under § 62.16415 

shall be construed as exempting or 

excluding the owners and operators, 

and the designated representative, of an 

affected EGU from compliance with any 

other provision of the applicable, 

approved state implementation plan, a 

federally enforceable permit, or any 

other requirement of the Clean Air Act. 

§ 62.16425 How should I compute time 

under the CO2 Rate-based Trading 

Program? 

(a) Unless otherwise stated, any time 

period scheduled, under the CO2 RateBased Trading Program, to begin on the 

occurrence of an act or event shall begin 

on the day the act or event occurs. 

(b) Unless otherwise stated, any time 

period scheduled, under the CO2 RateBased Trading Program, to begin before 

the occurrence of an act or event will be 

computed so that the period ends the 

day before the act or event occurs. 

(c) Unless otherwise stated, if the final 

day of any time period, under the CO2

Rate-Based Trading Program, is not a 

business day, then the time period will 

be extended to the next business day. 

§ 62.16430 What are the administrative 

appeal procedures? 

The administrative appeal procedures 

for decisions of the Administrator under 

the CO2 Rate-based Trading Program are 

set forth in part 78 of this chapter. 

§ 62.16431 How will the Clean Energy 

Incentive Program be administered under 

the federal plan? 

(a)(1) The Administrator will 

participate in the Clean Energy 

Incentive Program, established under 

subpart UUUU of part 60 of this chapter, 

on behalf of any state for whom this 

subpart is promulgated as a federal plan 

under section 111(d) of the Act. The 

Administrator will award, on behalf of 

each such state, early action ERCs for 

generation and savings achieved in 2020 

and/or 2021 that result from the 

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following types of eligible renewable 

energy (RE) and demand-side energy 

efficiency (EE) projects: 

(i) Metered wind power; 

(ii) Metered solar power; and 

(iii) Demand-side EE implemented in 

a low-income community. 

(2) Eligible RE projects must 

commence construction, and eligible 

demand-side EE projects must 

commence implementation, after 

September 6, 2018 for those states on 

whose behalf the EPA is implementing 

the federal plan. Eligible projects must 

be located in or benefit the state on 

whose behalf the EPA is implementing 

the federal plan. 

(b) Early action ERCs will be 

distributed pursuant to a process to be 

prescribed by the Administrator, and in 

a manner to be demonstrated by the 

Administrator to have no impact on the 

aggregate emission performance of 

affected EGUs required to meet ratebased emission standards during the 

compliance periods. 

(c) The Administrator will match 

these early action ERCs with additional 

matching ERCs pursuant to a process to 

be prescribed by the Administrator. 

Matching awards will be made up to a 

limit equivalent to the state’s pro rata 

share of 300 million short tons of CO2

emissions. 

(d) The awards, including the 

matching award, will be executed as 

follows: 

(1) For RE projects that generate 

metered MWh from wind or solar 

resources: For every two MWh 

generated, the project will receive one 

early action ERC under paragraph (b) of 

this section and one matching ERC from 

the match under paragraph (c) of this 

section; and 

(2) For EE projects that benefit lowincome communities as determined by 

the Administrator solely for purposes of 

this subpart: For every two MWh in 

end-use demand savings achieved, the 

project will receive two early action 

ERCs under paragraph (b) of this section 

and two matching ERCs from the match 

under paragraph (c) of this section. 

Emission Rate Credit Issuance, 

Adjustment, and Revocation 

§ 62.16434 What affected EGUs qualify for 

generation of ERCs? 

(a) ERCs may only be issued to 

affected EGUs under the conditions 

listed in paragraphs (b) and (c) of this 

section. 

(b) For affected EGUs that emit below 

their applicable emission standard, the 

amount of ERCs generated must be 

calculated using the following equation: 

Where: 

ERCs = Number of emission rate credits 

generated by an affected EGU during an 

applicable compliance period (MWh). 

EGU emission standard = The emission 

standard the affected EGU must comply 

with during the applicable compliance 

period according to § 62.16420 (lb/

MWh). 

EGU emission rate = The affected EGU’s 

measured CO2 emission rate measured in 

accordance with § 62.16540 (lb/MWh). 

EGU generation = Total net energy output 

generation of the affected EGU during 

the applicable compliance period 

measured in accordance with § 62.16540 

(MWh). 

(c) Stationary combustion turbines 

that meet the definition of an affected 

EGU may generate net energy output 

MWh gas shift ERCs (GS–ERCs) for all 

hours of operation during a given 

compliance period according to 

paragraphs (c)(1) through (3) of this 

section. 

(1) To calculate the number of GS– 

ERCs: 

GS–ERCs = EGU Generation * 

Incremental Generation Factor * GS– 

ERC Emission Factor 

Where: 

GS–ERC = Net energy output MWh gas shift 

ERCs. 

EGU generation = Total net energy output 

generation of the affected EGU during 

the applicable compliance period 

measured in accordance with § 62.16540 

(MWh). 

Incremental Generation Factor = See Table 2 

of this subpart for the applicable factor 

for each compliance period. 

GS–ERC Emission Factor = Value calculated 

using equation (c)(2) of this section. 

(2) To calculate the GS–ERC Emission 

factor for your specific affected EGU you 

must use the following equation: 

Where: 

GS–ERC Emission Factor = Factor to be used 

in the equation in paragraph (c)(1) of this 

section for GS–ERC calculation. 

EGU emission rate = Affected EGU’s 

measured CO2 emission rate measured in 

accordance with § 62.16540 (lb/MWh). 

Steam turbine emission standard = Steam 

turbine emission standard for the 

corresponding compliance period as 

found in Table 1 of this subpart (lb/

MWh). 

(3) Notwithstanding any other 

provision of this subpart, GS–ERCs must 

not be used for compliance by an 

affected EGU that is a stationary 

combustion turbine. Stationary 

combustion turbines may use other 

ERCs in their compliance 

demonstration. 

§ 62.16435 What eligible resources qualify 

for generation of ERCs in addition to 

affected EGUs? 

(a) ERCs may only be issued to an 

eligible resource that meet each of the 

requirements in paragraphs (a)(1) 

through (4) of this section. All categories 

of resources other than on-shore utility 

scale wind, utility scale solar 

photovoltaics, concentrated solar power, 

geothermal power, nuclear energy, or 

utility scale hydropower, and all 

provisions of this subpart relating to 

such resources, are not available or 

applicable in States where this subpart 

has been promulgated as a federal plan 

pursuant to section 111(d)(2) of the Act. 

(1) Resources qualifying for eligibility 

only include resources which increased 

new installed electrical generation 

nameplate capacity, or new electrical 

savings measures installed or 

implemented after January 1, 2013. If a 

resource had a nameplate capacity 

uprate, then ERCs may be issued only 

for the difference in generation between 

the uprated nameplate capacity and its 

nameplate capacity prior to the uprate. 

ERCs must not be issued for generation 

for an uprate that followed a derate that 

occurred on or after January 1, 2013. A 

resource that is relicensed or receives a 

license extension is considered existing 


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capacity and is not an eligible resource, 

unless it receives a capacity uprate as a 

result of the relicensing process that is 

reflected in its relicensed permit. In 

such a case, only the difference in 

nameplate capacity between its 

relicensed permit and its prior permit is 

eligible to be issued ERCs. 

(2) The resource must be connected 

to, and delivers energy to or saves 

electricity, on the electric grid in the 

contiguous United States. 

(3) The resource is located in a State 

whose affected EGUs are subject to ratebased emission standards pursuant to 

this regulation, unless the resource is 

located in a State with mass-based 

emission standards and the resource can 

demonstrate (e.g., through a power 

purchase agreement or contract for 

delivery) transmission of its generation 

into a State whose affected EGUs are 

subject to rate-based emission standards 

pursuant to this regulation. 

(4) The resource falls into one of the 

following categories of resources: 

(i) Renewable electric generating 

technologies using one of the following 

renewable energy resources: wind, solar, 

geothermal, hydro, wave, tidal; 

(ii) Qualified biomass; 

(iii) Waste-to-energy (biogenic 

portion); 

(iv) Nuclear energy; 

(v) A non-affected combined heat and 

power unit, including waste heat power; 

or 

(vi) A demand-side EE or demandside management measure that saves 

electricity and is calculated on the basis 

of quantified ex poste savings, not 

‘‘projected’’ or ‘‘claimed’’ savings. 

(b) Any resource that does not meet 

the requirements of this subpart cannot 

generate ERCs for use in the compliance 

demonstration required under 

§ 62.16420. 

(c) ERCs may not be issued to any of 

the following: 

(1) New, modified, or reconstructed 

EGUs that are subject to subpart TTTT 

of part 60 of this chapter, except CHP 

units that meet the requirements of a 

CHP unit under paragraph (a) of this 

section; 

(2) EGUs that do not meet the 

applicability requirements of 

§ 62.16410, except CHP units that meet 

the requirements of a CHP unit under 

paragraph (a) of this section; 

(3) Measures that reduce CO2

emissions outside the electric power 

sector, including GHG offset projects 

representing emission reductions that 

occur in the forestry and agriculture 

sectors, direct air capture, and crediting 

of CO2 emission reductions that occur in 

the transportation sector as a result of 

vehicle electrification; and 

(4) Any measure not approved by the 

EPA to generate ERCs in connection 

with a specific State plan. 

§ 62.16440 What is the process for 

revocation of qualification status of an 

eligible resource? 

(a) If an eligible resource is found to 

not meet the requirements of § 62.16435 

in the Rate-based Trading Program, then 

the Administrator will revoke the 

eligibility of the eligible resource to be 

issued ERCs. In addition, the provisions 

of § 62.16450(d) may apply. 

(b) Any instance of intentional 

misrepresentation in an eligibility 

application or monitoring and 

verification (M&V) report may be cause 

for revocation of the qualification status 

of an eligible resource. 

(c) Repeated instances of error or 

misstatement of MWh of electricity 

generation or savings in submitted M&V 

reports, or in any other submissions 

may be cause for the Administrator to 

revoke the eligibility of an eligible 

resource to be issued ERCs. 

(d) In the event of an intentional 

misrepresentation, or repeated instances 

of error or misstatement, in program 

submissions, by the authorized account 

representative of the eligible resource, 

the Administrator may prohibit the 

eligible resource from any further 

eligibility to be issued ERCs. In 

addition, the provisions of § 62.16450 

(a) through (d) may apply. 

§ 62.16445 What is the process for the 

issuance of ERCs? 

The process and requirements for 

issuance of ERCs for affected EGUs and 

eligible resources are set forth in 

paragraphs (a) through (f) of this section. 

(a) Eligibility application. To receive 

ERCs, an authorized account 

representative of an eligible resource 

must submit an eligibility application to 

the Administrator that demonstrates 

that the requirements of § 62.16434 (for 

an affected EGU) or § 62.16435 (for an 

eligible resource) are met, and, in the 

case of an eligible resource only, 

demonstrates that the requirements in 

paragraphs (a)(1) through (9) of this 

section are met. 

(1) Identification of the authorized 

account representative of the eligible 

resource, including the authorized 

account representative’s name, address, 

email address, telephone number, and 

ERC tracking system account number. 

(2) Identification of the eligible 

resource(s), including the information in 

paragraphs (a)(2)(i) through (v) of this 

section. 

(i) For an eligible resource, the 

physical location of the eligible 

resource; contact information for the 

owner or operator of the eligible 

resource, if different from the 

designated representative or authorized 

account representative; eligible resource 

generator prime mover and/or 

technology type; eligible resource 

nameplate capacity; eligible resource 

category (e.g., wholesale generator, 

wholesale generator also serving onsite 

customer load, customer-sited 

distributed generator) (if applicable); 

facility and generating unit IDs (EIA 

ORIS Code, Facility Registration System 

(FRS) Code, if applicable); for the 

eligible resource, the control area, 

balancing authority, ISO conditions as 

defined in § 62.16570, or the regional 

transmission organization in which the 

generator is located (if applicable). 

(A) For an eligible resource with a 

nameplate capacity of1 MW or more, a 

copy of the most recent filing of a copy 

of the generating facility’s U.S. Energy 

Information Agency’s Annual Electric 

Generator Report Form EIA–860. 

(B) For an electric generating resource 

with a nameplate capacity of less than 

1 MW, the information that would be 

contained in U.S. Energy Information 

Agency’s Annual Electric Generator 

Report Form EIA–860, if that electric 

generating facility had nameplate 

capacity of 1 MW or more. 

(ii) For an energy-saving resource that 

is project-based, a detailed description 

of the demand-side EE or electricity 

savings project, including: Location and 

specifications of the building(s), 

facility(ies), or installations where 

energy-saving measures were 

implemented or will be implemented; 

owner and operator of the building(s), 

facility(ies), or installations where the 

energy-saving measures are 

implemented or will be implemented; 

the parties implementing the energysaving project, including lead 

contractor(s), subcontractors, and 

consulting firms (if different from the 

authorized account representative); 

energy-saving measures installed and/or 

energy-savings practices implemented 

(or to be installed/implemented); 

specifications of equipment and 

materials installed, or to be installed, as 

part of the energy-saving project; project 

plans and technical schematics, as 

applicable. 

(iii) For an energy-savings resource 

that involves an EE requirement or 

program, a description of the electricity 

savings program, including: Overall 

approach or ‘‘logic’’ to the requirement 

or program, including applicable 

strategies and activities, along with key 

assumptions regarding how such 

strategies and activities will achieve 

quantifiable reductions in electricity 

consumption; location and geographic 

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distribution of the targeted building(s), 

facility(ies), or installations where 

energy-saving requirements or programs 

were implemented or will be 

implemented; electricity consuming 

system(s), end-use(s), building or 

facility type(s), or installations where 

the energy-saving requirements or 

programs are implemented or will be 

implemented; the parties implementing 

the energy-saving requirement or 

program, including lead contractor(s), 

subcontractor(s), and consulting firms 

(if different from the authorized account 

representative); specifications of energysaving equipment and/or energy-savings 

practices implemented (or to be 

installed/implemented) under the 

requirement or program; the delivery 

mechanisms of the requirement or 

program, which may include financial 

incentives or equipment rebates, 

dissemination of actionable information 

to electricity customers, on-site audits 

paired with technical recommendations. 

(iv) For other electricity-saving 

resources (e.g., transmission and 

distribution (T&D) measures such as 

conservation voltage reduction (CVR)), a 

description of the resource, including: 

Overall approach or ‘‘logic’’ to the 

electricity-saving resource, including 

applicable strategies and activities, 

along with key assumptions regarding 

how such strategies and activities will 

achieve quantifiable reductions in 

electricity consumption; location and 

geographic distribution of the targeted 

building(s), facility(ies), or electricity 

transmitting and distributing systems, as 

applicable, where electricity-saving 

resources were implemented or will be 

implemented; electricity consuming, 

transmitting, or distributing system(s), 

building or facility type(s), or end-use(s) 

where the electricity-saving resource are 

implemented or will be implemented; 

the parties implementing the electricitysaving resource, including lead 

contractor(s), subcontractor(s), and 

consulting firms (if different from the 

authorized account representative); 

specifications of installed equipment 

and/or implemented practices (or to be 

installed/implemented); the delivery 

mechanisms used to implement and 

propagate the electricity-saving 

resource, as applicable. 

(v) For eligible resources with 

distributed locations, such as measures 

at multiple residential, commercial, or 

industrial buildings, at a minimum, 

aggregated information about the 

location of measures that constitute an 

eligible resource, provided that the 

accredited independent verifier and the 

Administrator have the ability to access 

information specifying the location of 

each discrete measure that constitutes 

an eligible resource. 

(3) Demonstration that the eligible 

resource meets all applicable eligibility 

requirements in § 62.1435. 

(4) A certification that the eligibility 

application has only been submitted to 

the Administrator or pursuant to an 

EPA-approved multi-state approach 

where States are providing for joint 

issuance of ERCs pursuant to the 

authority in their individual State plans. 

(5) An evaluation measurement and 

verification (EM&V) plan. 

(6) A verification report from an 

accredited independent verifier who 

meets the requirements of §§ 62.16470 

and 62.16475. 

(7) An authorization that provides for 

the following: The Administrator may 

inspect (including a physical inspection 

of the eligible resource and its meter) 

and/or audit the eligible resource at any 

time and verify that the eligible resource 

and the EM&V plan have been 

implemented as described in the 

eligibility application. 

(8) The following statement, signed by 

the designated representative of the 

eligible resource: 

(i) ‘‘I certify under penalty of law that 

I have personally examined, and am 

familiar with, the statements and 

information submitted in this document 

and all its attachments. Based on my 

personal knowledge and/or inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(ii) [Reserved] 

(9) Any other information required by 

the Administrator. 

(b) Registration of eligible resources. 

The Administrator must review the 

eligibility application to determine 

whether the affected EGU or eligible 

resource meets the requirements of 

§ paragraph (a) of this section, and if it 

determines that the requirements are 

met, approve the eligibility application 

and register the affected EGU or eligible 

resource in an ERC tracking system that 

meets the requirements of § 62.16515. 

Once so registered, the affected EGU or 

eligible resource is eligible to be issued 

ERCs, provided all other applicable 

requirements continue to be met. 

(c) M&V reports. For an eligible 

resource, the designated representative 

must submit to the Administrator an 

M&V report prior to issuance of ERCs by 

the Administrator. 

(d) Verification reports. For an eligible 

resource, the authorized account 

representative must submit a 

verification report from an accredited 

independent verifier that meets the 

requirements of §§ 62.16470 and 

62.16475 as part of each eligibility 

application and M&V report. While 

considered a part of the eligibility 

application and M&V report, the 

verification report must be submitted 

separately by the accredited 

independent verifier to the 

Administrator. 

(e) Issuance of ERCs. ERCs may only 

be issued by the Administrator based on 

actual electricity generation or savings 

documented in an M&V report that 

meets the requirements of § 62.16460 

and a verification report that meets the 

requirements of § 62.16465. Only one 

ERC will be issued for each verified 

MWh. 

(f) Tracking system. ERCs may only be 

issued through an ERC tracking system 

that meets the requirements of 

§ 62.16515. 

§ 62.16450 What is the process for error 

adjustments or misstatement, and 

suspension of ERC issuance? 

(a) In the event of error or 

misstatement of quantified MWh of 

electricity generation or savings in a 

previous M&V report for which ERCs 

have been issued, the Administrator 

may adjust the number of ERCs issued 

in a subsequent reporting period to 

address the error or misstatement, by 

subtracting a number of MWh from the 

quantified and verified MWh in the 

M&V report for the subsequent reporting 

period. In the event that an error or 

inadvertent misstatement occurs in a 

final M&V report for an eligible 

resource, for which ERCs have been 

issued, the provisions of paragraph (b) 

of this section will apply. 

(b) In the event of error or 

misstatement of quantified MWh of 

electricity generation or savings in the 

final M&V report for an eligible 

resource, for which ERCs have been 

issued, the Administrator will revoke 

ERCs from the general account held by 

the authorized account representative of 

the eligible resource, in an amount 

necessary to correct the error or 

misstatement. In the event that the 

general account of the eligible resource 

holds an insufficient number of ERCs to 

correct the error or misstatement, the 

authorized account representative must 

submit to the Administrator within 30 

days a number of ERCs necessary to 

correct the error or misstatement. 

Failure to meet this requirement will 

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result in prohibition of the authorized 

account representative for the eligible 

resource from further participation in 

the program, unless reauthorized at the 

discretion of the Administrator. 

(c) The Administrator may freeze the 

general account held by an authorized 

account representative of an eligible 

resource at any time, for cause, if the 

Administrator determines ERCs have 

been improperly issued, based on a 

misrepresentation or misstatement in an 

eligibility application or M&V report. 

The Administrator may also freeze the 

general account of an authorized 

account representative of an eligible 

resource pending investigation of 

potential misrepresentation, error, or 

misstatement in an eligibility 

application of an eligible resource, or in 

an M&V report for which ERCs have 

been issued. Freezing a general account 

will prevent transfer of ERCs out of the 

account. 

(d) If ERCs are issued for an eligible 

resource that is found to be ineligible, 

then the Administrator may take the 

actions in paragraphs (d)(1) through (3) 

of this section. 

(1) Freeze the general account for the 

eligible resource, preventing any 

transfers of ERCs out of the account. 

(2) Revoke and deduct ERCs held in 

the general account of the authorized 

account representative for an eligible 

resource, in a number equal to the 

number of ERCs issued for the ineligible 

eligible resource. 

(3) In the event that the general 

account of the eligible resource holds a 

number of ERCs less than the number of 

ERCs issued for the ineligible eligible 

resource, the delegated representative of 

an eligible resource must submit to the 

Administrator within 30 days a number 

of ERCs necessary to fully account for 

all ERCs issued for the ineligible eligible 

resource. Failure to meet this 

requirement will result in prohibition of 

the eligible resource from further 

participation in the program, unless 

reauthorized at the discretion of the 

Administrator. 

(e) The Administrator may 

temporarily or permanently suspend 

issuance of ERCs for an eligible 

resource, for the following reasons in 

paragraphs (e)(1) through (3) of this 

section. 

(1) Pending investigation of potential 

misrepresentation, error, or 

misstatement in an M&V report, for 

which ERCs have been issued, or the 

eligibility status of an eligible resource. 

(2) In the case of repeated error or 

misstatements in submitted M&V 

reports. 

(3) In the case of an intentional 

misrepresentation in a submitted M&V 

report. 

Evaluation Measurement and 

Verification Plans, Monitoring and 

Verification Reports, and Verification 

§ 62.16455 What are the requirements for 

evaluation measurement and verification 

plans for eligible resources? 

(a) EM&V plan requirements. Any 

EM&V plan submitted in support of the 

issuance of an ERC pursuant to this rule 

must meet the requirements of this 

section. 

(b) General EM&V plan criteria. Each 

EM&V plan must identify the eligible 

resource and its approved eligibility 

application. 

(c) Specific EM&V plan criteria. Each 

EM&V plan must provide the manner in 

which the electricity generated or saved 

by the eligible resource will be 

quantified, monitored and verified, and 

the manner of quantification, 

monitoring and verification must meet 

the criteria listed in paragraphs (c)(1) 

through (7) of this section, as applicable 

to the specific eligible resource. 

(1) For a nuclear energy resource or a 

renewable energy resource with a 

nameplate capacity of 10 kW or more 

and for a renewable energy resource 

with a nameplate capacity of less than 

10 kW for which metered data are 

available, each EM&V plan must specify 

that the requirements in paragraphs 

(c)(1)(i) through (vi) of this section are 

met. 

(i) The generation data are physically 

measured on a continuous basis using a 

revenue-quality meter, which means a 

meter used by a control area operator for 

financial settlements, or a meter that 

meets the American National Standards 

Institute No. C12.20., Code for 

Electricity Metering, metering accuracy 

standards, or a meter that meets an 

alternative equivalent standard that has 

been approved in advance of its use to 

measure generation pursuant to this 

regulation by the EPA. 

(ii) The generating data are measured 

at the generator’s bus bar, or, for a 

renewable energy resource with a 

nameplate capacity of less than 10 kW 

that is interconnected behind an 

individual business or household meter, 

the generating data were measured at 

the AC output of the inverter and 

adjusted to reflect the only energy 

delivered into either the transmission or 

distribution grid at the generator bus bar 

and not any energy used on-site at the 

generator. 

(iii) The generation data from only 

one eligible resource generating unit 

may be associated with each meter, and 

generation data may not be aggregated, 

unless all the following provisions are 

met: 

(A) All of the generating units have 

the same essential generation 

characteristics; 

(B) All of the generating units are 

located in the same State; 

(C) The nameplate capacity of the 

individual units being aggregated is 

each less than 150 kW, and units 

collectively do not exceed a total 

nameplate capacity of 1 MW when 

aggregated, or alternative requirements 

approved by the EPA in connection 

with the specific State plan pursuant to 

which that EM&V plan or M&V report 

is submitted; and 

(D) The generation data are measured 

by the same type of meter that is subject 

to the same maintenance and quality 

assurance procedures. 

(iv) The generation data are collected 

electronically and telemetered from the 

generator to its control area operator and 

verified through a control area energy 

accounting or settlement process which 

occurs at least monthly, unless the 

generation unit does not go through a 

control area operator, in which case the 

generation data must be collected by 

manual meter readings conducted by an 

independent verifier that is either not 

affiliated with the owner or operator of 

the qualifying renewable energy 

generating resource or is precluded 

pursuant to the relevant State plan from 

the ability to transfer or retire ERCs 

issued to that qualifying renewable 

energy generating resource or, if the 

generating unit is less than 10 kw and 

does not generate enough electricity to 

enable monthly reporting, then the data 

may be self-reported and reported no 

less than annually. 

(v) The generation data serve a load 

that otherwise would have been served 

by the grid if not for the generator. 

Specifically: 

(A) ERCs shall not be issued for 

energy generation used to supply the 

ancillary equipment used to operate a 

generating station or substation (‘‘station 

service’’) or parasitic load on the 

generator’s side of the point of 

interconnection; and 

(B) For generators interconnected to 

transmission systems and with on-site 

loads other than station service drawing 

generation before the metering point, 

ERCs may be issued for on-site load, if 

the owner or operator of the eligible 

resource can demonstrate that the 

metering used is capable of 

distinguishing between on-site load and 

station service. 

(vi) Any other requirements approved 

by the EPA in connection with the 

specific State plan pursuant to which 

that EM&V plan is submitted. 

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(2) For a renewable energy resource 

with a nameplate capacity of less than 

10 kW and that does not have a meter, 

each EM&V plan must require that the 

following requirements in paragraphs 

(c)(2)(i) though (vii) of this section are 

met. 

(i) Metered data are unavailable. 

(ii) At least 1 MW of net energy 

output is generated to the distribution or 

transmission system over a continuous 

365-day period. 

(iii) The generation data may not be 

aggregated, unless the following 

provisions are met: 

(A) All of the generating units have 

the same essential generation 

characteristics; 

(B) All of the generating units are 

located in the same State; 

(C) The nameplate capacity of the 

individual units being aggregated is 

each less than 150 kW, and units 

collectively do not exceed a total 

nameplate capacity of 1 MW when 

aggregated, or alternative requirements 

approved by the EPA in connection 

with the specific State plan pursuant to 

which that EM&V plan or M&V report 

is submitted; and 

(D) The generation data are measured 

by the same generation estimating 

software or algorithms. 

(iv) The generation data are measured 

on at least a monthly basis using 

generation estimating software or 

algorithms that are based on an on-site 

inspection prior to interconnection and 

a resource study (wind, shading, solar 

irradiance, depending on the resource), 

or engineering information that takes 

into account the capacity, age, and type 

of qualifying energy generating resource, 

and all input parameters and 

assumptions must be clearly delineated, 

or if the generating unit does not 

generate enough electricity to enable 

monthly reporting, then the data may be 

reported no less than annually. 

(v) The generation data are selfreported to the distribution utility 

through an electronic internet-based 

portal with software that reports total 

and hourly generation. 

(vi) The generation data serve a load 

that otherwise would have been served 

by the grid if not for the generator. The 

ERC is only based on generation 

transferred from the eligible resource to 

the transmission or distribution grid, 

and is not based on the generation used 

on-site by the customer. 

(vii) Any other requirements 

approved by the EPA in connection 

with the specific State plan pursuant to 

which that EM&V plan is submitted. 

(3) For qualified biomass feedstocks 

used, in addition to the requirements of 

paragraphs (c)(1) or (2) of this section, 

whichever section is applicable, each 

EM&V plan must demonstrate that the 

requirements approved by the EPA for 

that biomass feedstock, and its 

associated biogenic CO2, have been met. 

(4) For a waste-to-energy resource, in 

addition to the requirements of 

paragraphs (c)(1) or (2) of this section, 

as applicable, and paragraph (c)(3) of 

this section, each EM&V plan must 

specify: 

(i) The total net energy generation 

from the resource in MWh; 

(ii) The method for determining the 

specific portion of the total net energy 

output from the resource that is related 

to the biogenic portion of the waste 

materials; and 

(iii) The net energy output measured 

with the relevant method approved by 

the EPA in connection with the specific 

State plan pursuant to which that EM&V 

plan is submitted demonstrates that the 

requirements approved by the EPA in 

connection with that State plan have 

been met. 

(5) For a combined heat and power 

unit, in addition to the requirements of 

paragraphs (c)(1) or (2) of this section, 

as applicable, and paragraph (c)(3) of 

this section, each EM&V plan must meet 

one of the requirements in paragraphs 

(c)(5)(i) through (iv) of this section, as 

applicable, and any other requirements 

approved by the EPA. 

(i) If the combined heat and power 

unit has an electric generating capacity 

greater than 25 MW, then the EM&V 

plan must meet the requirements that 

apply to an affected EGU under 

§ 62.16540. 

(ii) If the combined heat and power 

unit has an electric generating capacity 

less than or equal to 25 MW and greater 

than 1 MW, and it uses only natural gas 

and/or distillate fuel oil, then the EM&V 

plan must meet the low mass emission 

unit CO2 emission monitoring and 

reporting methodology in part 75 of this 

chapter. 

(iii) If the combined heat and power 

unit has an electric generating capacity 

less than or equal to 25 MW and greater 

than 1 MW, and it uses anything other 

than only natural gas and/or distillate 

fuel oil, then the EM&V plan must meet 

the low mass emission unit CO2

emission monitoring and reporting 

methodology in part 75 of this chapter. 

(iv) If the combined heat and power 

unit has an electric generating capacity 

less than or equal to 1 MW the unit 

must keep monthly cumulative 

recordings of useful thermal output and 

fossil fuel input along with the 

determination of baseline thermal 

source efficiencies based on 

manufacturer data. For CHP units that 

directly serve on-site end-use electricity 

loads, avoided T&D system losses can be 

assessed as is commonly practiced with 

demand-side EE. 

(6) For demand-side electricity 

savings that avoid a transmission and 

distribution loss, each EM&V plan must 

measure the transmission and 

distribution loss based on the lesser of 

6 percent of the facility- or premiseslevel electricity savings measured at the 

electricity customer’s 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. No other 

transmission and distribution loss 

factors may be used in calculating the 

electricity savings. 

(7) Each EM&V plan for an EE 

program, EE project, or EE measure 

must specify how each of the 

requirements in paragraphs (c)(7)(i) 

through (x) of this section will be met 

in quantifying the electricity savings 

from that EE program, EE project, or EE 

measure. 

(i) All electricity savings must be 

quantified on an ex-post basis, which 

means after the electricity savings have 

occurred, or on a real-time basis, which 

means at the time the electricity savings 

are occurring. Electricity savings must 

not be quantified on an ex-ante basis, 

which means estimates of MWh savings 

that are generated prior to implementing 

the subject EE program, EE project, or 

EE measure, and that are not quantified 

using EM&V methods and procedures. 

(ii) All electricity savings must be 

quantified and verified based on 

methods and procedures detailed in an 

industry best-practice EM&V protocol or 

guideline. Each EM&V plan must 

include a demonstration of how the 

best-practice protocol or guideline was 

selected and will be applied to the 

specific EE program, EE project, or EE 

measure covered in the EM&V plan, and 

an explanation of why that particular 

protocol or guideline was selected. 

Protocols and guidelines are considered 

to be best practice if they: 

(A) Have gone through a rigorous and 

credible peer review process that shows 

the applicable methods to be valid 

through empirical testing; and 

(B) Have been accepted and approved 

for use by identifiable state regulatory 

commissions. Examples of such 

protocols and guidelines that may be 

provided in EM&V guidance issued by 

the Administrator will be acceptable. 

(iii) All electricity savings must be 

quantified as the difference between the 

observed electricity use and a common 

practice baseline (CPB), which is the 

equipment that would typically have 

been installed—or that a typical 

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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. 

Examples of CPBs for specific EE 

programs, EE projects, EE measures, and 

for certain EM&V methods that may be 

provided in EM&V guidance issued by 

the Administrator will be acceptable. 

The EM&V plan must specify the reason 

the specific CPB was selected, which 

must include an analysis of the 

appropriateness of that CPB for the EE 

program, EE project, or EE measure 

covered in the EM&V plan, based on: 

(A) Characteristics of the EE program, 

EE project, or EE measure; 

(B) The delivery mechanism used to 

implement the EE program, EE project, 

or EE measure (e.g., installed as part of 

a utility EE program versus a point-ofsale rebate); 

(C) Local consumer and market 

characteristics; 

(D) Applicable building energy codes 

and standards and average compliance 

rates; and 

(E) The method applied: Project-based 

measurement and verification (PB–MV), 

comparison group approaches, or 

deemed savings. 

(iv) All electricity savings must be 

quantified by applying one or more of 

the following methods: Project-based 

measurement and verification (PB–MV), 

comparison group approaches, or 

deemed savings. 

(A) If a comparison group approach is 

used, then the EM&V plan must 

quantify electricity savings by taking the 

difference between a comparison 

group’s electricity use and the 

electricity use of EE program 

participants. Comparison group 

approaches may include randomized 

control trials and quasi-experimental 

methods, as described in industry bestpractice protocols and guidelines. 

Examples of such protocols and 

guidelines provided in EM&V guidance 

that may be issued by the Administrator 

will be acceptable. 

(B) If deemed savings are used, then 

the EM&V plan must specify that the 

deemed savings values will only be 

used for the specific EE measure for 

which they were derived. The EM&V 

plan must also specify the name and 

Web address of the technical reference 

manual (TRM) in which all deemed 

electricity savings values will be 

documented. Prior to use in an EM&V 

plan, all TRMs must undergo a review 

process in which the public, 

stakeholders, and experts are invited— 

with adequate advance notification (via 

the internet and other social media)—to 

provide comment, have at least 2 

months to provide comment, and in 

which all such comments and 

associated responses are made publicly 

available. All TRMs must also be 

publicly accessible over the full period 

of time in which they are being used in 

conjunction with an EM&V plan for the 

purpose of quantifying savings, and 

must be subsequently updated in the 

same manner at least every 3 years. The 

TRM must indicate, for each subject EE 

measure, the associated electricity 

savings value, the conditions under 

which the value can be applied 

(including the climate zone, building 

type, manner of implementation, 

applicable end uses, operating 

conditions, and effective useful life), 

and the manner in which the electricity 

savings value was quantified, which 

must include applicable engineering 

algorithms, source documentation, 

specific assumptions, and other relevant 

data to support the quantification of 

savings from the subject EE measure. 

(v) All EE programs, EE projects, or EE 

measures must be quantified at time 

intervals (in years) sufficient to ensure 

that MWh savings are accurately and 

reliably quantified. Such time intervals 

must be specified and explained in the 

EM&V plan. Factors that must be taken 

into consideration when determining 

the appropriate time interval include 

the characteristics of the specific EE 

program, EE project, or EE measure, 

expected variability in electricity 

savings (where greater variability 

necessitates more frequent 

quantification), the expected scale and 

magnitude of the electricity savings 

(where greater quantities of savings 

necessitate more frequent 

quantification), and the experience 

implementing and quantifying savings 

from the resource (where less 

experience—for example, with new and 

innovative EE program types— 

necessitates more frequent 

quantification). The time intervals must 

end no sooner than the last day of the 

effective useful life of the EE program, 

EE project, or EE measure, and must last 

no longer than: 

(A) Every 4-year intervals for building 

energy codes and product standards; 

(B) Every 1, 2, or 3 years for public or 

consumer-funded EE program, EE 

project, or EE measure, as relevant for 

the type of EE program, EE project, or 

EE measure and factors listed in 

paragraph (c)(7)(v) of this section; and 

(C) Annually for commercial and 

industrial projects, unless the resource 

provider can provide a reasonable 

justification in the EM&V plan for why 

an annual time interval is not feasible, 

and can additionally explain how the 

accuracy and reliability of savings 

values will not be lessened. 

(vi) EM&V plans must specify and 

document how the EM&V components 

in paragraphs (c)(7)(vi)(A) through (E) of 

this section will be analyzed, 

considered, or otherwise addressed in 

the quantification and verification of 

electricity savings. 

(A) The effects of changes in 

independent factors on reported 

electricity savings (i.e., factors that are 

not directly related to the EE measure, 

such as weather, occupancy, and 

production levels). 

(B) The effective useful life (EUL) or 

duration of time the EE measure is 

anticipated to remain in place and 

operable with the potential to save 

electricity, which must be based on the 

application of EM&V methods, an 

industry best-practice persistence study, 

deemed estimates of effective useful life, 

or a combination of all three. 

(1) If deemed estimates of effective 

useful life are used, then they must 

specify the date by which the EE 

measure will stop saving electricity. 

(2) If industry best-practices 

persistence studies are used to modify 

an effective-useful-life value, then they 

must be conducted at least every 5 

years. 

(C) The potential sources of double 

counting, and the associated steps for 

avoiding and correcting for it, such as: 

(1) For an EE program or EE project 

with identified participants, track the 

type and number of EE measures 

implemented at the utility-customer 

level. 

(2) For an EE program or EE project 

without identified participants, such as 

point-of-sale rebates and retailer or 

manufacturer incentive programs, track 

applicable vendor, retailer, and 

manufacturer data. 

(3) For EE programs (such as those 

implemented by a utility) and EE 

projects (such as those implemented by 

an energy service company) that both 

have identified participants, use 

tracking data to avoid and correct for 

double counting that may occur across 

the two; and 

(4) For EE programs with identified 

participants and those without (such as 

retail incentives to purchase energyefficient equipment), use EE program 

tracking data for the former and use 

applicable vendor, retailer, and 

manufacturer data for the latter to avoid 

and correct for double counting that 

may occur across the two. 

(D) The EE savings verification 

approaches for ensuring that EE 

measures have been properly installed, 

are operating as intended, and therefore 

have the potential to save electricity, 

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including how verification will be 

carried out within the first year of 

implementation of the EE program, EE 

project, or EE measure using bestpractice approaches, such as physical 

inspections at a customer’s premises, 

phone and mail surveys, and reviews of 

sales receipts and other documentation. 

If such approaches are documented in 

EM&V guidance issued by the 

Administrator, they will be treated as 

acceptable. 

(E) The interactive effects of EE 

programs, EE projects, or EE measures 

on electricity usage, which are increases 

or decreases in electricity usage at an 

end-use facility or premises that occurs 

outside of specific end-uses(s) targeted 

by the EE program, EE project, or EE 

measure (e.g., lighting retrofits to 

improve EE can reduce waste heat to the 

surrounding conditioned space, and 

therefore may increase the required 

electric heating load in a facility or 

premises). 

(vii) The EM&V plan must specify 

how the accuracy and reliability of the 

electricity savings of the EE program, EE 

project, or EE measure will be assessed, 

and must discuss the rigor of the 

method selected to quantify the 

electricity savings. It must also discuss 

the approaches that will be used to 

control all relevant types of bias and to 

minimize the potential for systematic 

and random error, as well as the 

program- or project-specific 

circumstances in which such bias and 

error are likely to arise. Approaches to 

minimizing bias and error are provided 

in the EM&V guidance that may be 

issued by the Administrator will be 

acceptable. 

(viii) If sampling will be used to 

quantify the electricity savings from an 

EE program, then the MWh estimates 

derived from sampling must have at 

least 90 percent confidence intervals 

whose end points are no more than ±10 

percent of the estimate, and the 

statistical precision of the associated 

estimates must be specified in the 

EM&V plan. 

(ix) All data sources and key 

assumptions used to quantify electricity 

savings must be described in the EM&V 

plan. 

(x) Any additional information 

necessary to demonstrate that the 

electricity savings were appropriately 

quantified and verified. Approaches to 

quantifying and verifying savings from 

several EE program and EE project types 

that are provided in EM&V guidance 

that may be issued by the Administrator 

will be acceptable. 

(d) You must ensure that any EM&V 

plan submitted pursuant to this subpart 

includes the following certification: 

(1) ‘‘I certify under penalty of law that 

I have personally examined, and am 

familiar with, the statements and 

information submitted in this document 

and all its attachments. Based on my 

inquiry of those individuals with 

primary responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(2) [Reserved] 

§ 62.16460 What are the requirements for 

monitoring and verification reports for 

eligible resources? 

(a) M&V report requirements. Any 

M&V report that is submitted, in 

support of the issuance of an ERC that 

can be used in accordance with 

§ 62.16420, must meet the requirements 

of this section. 

(b) General M&V report criteria. Each 

M&V report must include the following: 

(1) For the first M&V report 

submitted, documentation that the 

electricity-generating resources, 

electricity-saving measures, or practices 

were installed or implemented 

consistent with the description in the 

approved eligibility application 

required in § 62.16445(a); and 

(2) For each M&V report submitted: 

(i) Identification of the time period 

covered by the M&V report; 

(ii) A description of how relevant 

quantification methods, protocols, 

guidelines, and guidance specified in 

the EM&V plan were applied during the 

reporting period to generate the 

quantified MWh of generation or MWh 

of electricity savings; 

(iii) Documentation (including data) 

of the energy generation and/or 

electricity savings from any activity, 

project, measure, resource, or program 

addressed in the EM&V report, 

quantified and verified in MWh for the 

period covered by the M&V report, in 

accordance with its EM&V plan, and 

based on ex-post energy generation or 

savings; 

(iv) Documentation of any change in 

the energy generation or savings 

capability of the eligible resource during 

the period covered by the M&V report 

and the date on which the change 

occurred, and either certification that 

the eligible resource continued to meet 

all eligibility requirements during the 

reporting period covered by the M&V 

report or disclosure of any material 

changes to the eligible resource from the 

description of the eligible resource in 

the approved eligibility application, 

which must include any change in the 

energy generation (e.g., nameplate MW 

capacity) or electricity savings 

capability of the qualifying eligible 

resource (including the date of the 

change); and 

(v) Documentation of any change in 

ownership interest of the qualifying 

eligible resource (including the date of 

the change). 

(c) You must ensure that any M&V 

report submitted pursuant to this 

subpart includes the following 

certification: 

(1) ‘‘I certify under penalty of law that 

I have personally examined, and am 

familiar with, the statements and 

information submitted in this document 

and all its attachments. Based on my 

inquiry of those individuals with 

primary responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(2) [Reserved] 

§ 62.16465 What are the requirements for 

verification reports? 

(a) A verification report included as 

part of an eligibility application or an 

M&V report must meet the requirements 

of paragraph (b) of this section (for the 

eligibility application verification 

report) and paragraph (c) of this section 

(for the M&V report verification report) 

and include the following: 

(1) A verification statement that sets 

forth the findings of the accredited 

independent verifier, based on the 

verifier’s assessment of the information 

and data in the eligibility application or 

M&V report that is the subject of the 

verification report, including an 

assessment of whether the eligibility 

application or M&V report contains any 

material misstatements or material data 

discrepancies, and whether the 

submittal conforms with applicable 

regulatory requirements. The 

verification statement must clearly 

identify how levels of assurance and 

materiality are defined as part of the 

verifier assessment. 

(2) The following statement, signed by 

the accredited independent verifier: ‘‘I 

certify under penalty of law that I have 

personally examined, and am familiar 

with, the statements and information 

submitted in this document and all its 

attachments. Based on my personal 

knowledge and/or inquiry of those 

individuals with primary responsibility 

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for obtaining the information, I certify 

that the statements and information are 

to the best of my knowledge and belief 

true, accurate, and complete. I am aware 

that there are significant penalties for 

submitting false statements and 

information or omitting required 

statements and information, including 

the possibility of fine or imprisonment.’’ 

(b) A verification report included as 

part of an eligibility application must, at 

a minimum, describe the review 

conducted by the accredited 

independent verifier and verify each of 

the following: 

(1) The eligibility of the eligible 

resource to be issued ERCs pursuant to 

this regulation, in accordance with 

§ 62.16435 and § 62.16445(a), including 

an analysis of the adequacy and validity 

of the information submitted by the 

authorized account representative to 

demonstrate that the eligible resource 

meets each applicable requirement of 

§ 62.16435 and § 62.16445(a). 

(2) The eligible resource is not 

duplicative of a resource used to meet 

emission standards or a state measure in 

another approved State plan. 

(3) The eligible resource exists or the 

practice or activity will be implemented 

in the manner specified in the eligibility 

application. 

(4) The EM&V plan meets the 

requirements of § 62.16455. 

(5) Disclosure of any mandatory or 

voluntary programs to which data is 

reported relating to the eligible resource 

(e.g., reporting of electric generation by 

a renewable energy resource to a 

renewable energy certificate tracking 

system). 

(6) Any other information required by 

the Administrator or that the accredited 

independent verifier finds, in its 

professional opinion, is necessary to 

assess the adequacy and validity of 

information and data supplied by the 

authorized account representative. 

(c) A verification report included as 

part of a M&V report must, at a 

minimum, describe the review 

conducted by the accredited 

independent verifier and verify the 

following: 

(1) The adequacy and validity of the 

information and data submitted in the 

submittal by the authorized account 

representative to quantify eligible MWh 

of electric generation or electricity 

savings during the period for which the 

authorized account representative seeks 

issuance of ERCs, as well as all 

supporting information and data 

identified in the EM&V plan and M&V 

report. This analysis must include a 

quality assurance and quality control 

check of the data and ensure that all 

generation or savings data are within a 

technically feasible range for that 

specific eligible resource. 

(i) For metered generation, the data 

validity check must compare reported 

electricity generation to an engineering 

estimate of the maximum generation 

potential of the qualified renewable 

energy resource, based on, at a 

minimum, its maximum nameplate 

capacity in MW and the number of days 

since the prior cumulative meter 

reading was entered in the ERC tracking 

system. If the data entered exceed the 

estimated technically feasible 

generation, then the reported data and 

the estimate must be analyzed in the 

verification report. 

(ii) For all electricity generated or 

saved, the accredited independent 

verifier must describe the likely source 

of any data discrepancy and determine 

in the verification report any MWh 

generated or saved. 

(2) The M&V report meets the 

requirements of § 62.16460. 

(3) Any other information required by 

the Administrator or that the accredited 

independent verifier finds, in its 

professional opinion, is necessary to 

assess the adequacy and validity of 

information and data supplied by the 

authorized account representative. 

§ 62.16470 What is the accreditation 

procedure for independent verifiers? 

(a) Only Administrator-accredited 

independent verifiers may provide a 

verification report for an eligibility 

application or M&V report. 

(b) Applications for accreditation 

must follow a procedure and form 

specified by the Administrator which 

includes a demonstration by the verifier 

that it meets the requirements in 

paragraph (c) of this section. 

(c) Independent verifiers must meet 

each of the requirements in paragraphs 

(c)(1) through (6) of this section to be 

accredited. 

(1) Independent verifiers must have 

the skills, experience, and resources 

(personnel and otherwise) to provide 

verification reports, including the 

following: 

(i) Appropriate technical qualification 

(professional engineer or otherwise) to 

evaluate the eligible resource for which 

the independent verifier is seeking 

accreditation, which may include ANSI 

accreditation under ISO 14065 for GHG 

validation and verification bodies; 

(ii) Appropriate auditing and 

accounting qualifications for financial 

and non-financial data monitoring, 

auditing, and quality assurance and 

quality control to evaluate the eligible 

resource for which the independent 

verifier is seeking accreditation; 

(iii) Knowledge of the requirements of 

the Administrator’s CO2 Rate-based 

Trading Program regulations and related 

guidance; 

(iv) Knowledge of the eligible 

resource categories for which the 

independent verifier is seeking 

accreditation, including relevant aspects 

of the design, operation, and related 

energy generation or electricity savings 

monitoring and reporting approaches for 

such eligible resources; and 

(v) Capability to perform key 

verification activities, such as 

development of a verification report; 

performance of site visits; review and 

recalculation of reported data; review of 

data management systems; review of 

quantification methods used in 

accordance with an approved EM&V 

plan; preparation of a verification 

statement, list of findings, and 

verification report; and internal review 

of the verification findings and report. 

(2) Independent verifiers must 

document, in the application for 

accreditation, the independent verifiers 

that will provide verification services, 

including lead verifiers, key personnel 

and any contractors or subcontractors 

(collectively, accredited independent 

verification team) and demonstrate that 

they meet the requirements of section 

§ 62.16470(d)(1). Once accredited, only 

the accredited independent verification 

team identified in the accreditation 

application and accredited by the State 

may provide a verification report. 

(3) An independent verifier must 

specify the eligible resource categories 

for which it is seeking accreditation, 

and an accredited independent verifier 

may only provide verification services 

related to an eligible resource category 

for which it is accredited. 

(4) Prospective independent verifiers 

must meet the requirements of 

§ 62.16475(d) through (f) and 

demonstrate that they have in place 

adequate systems and protocols to 

identify, disclose and avoid potential 

conflicts of interest. 

(5) An accredited independent verifier 

must not be debarred, suspended, or 

proposed for debarment pursuant to the 

Government-wide Debarment and 

Suspension regulations, part 32 of this 

chapter, or the Debarment, Suspension 

and Ineligibility provisions of the 

Federal Acquisition Regulations, 48 CFR 

part 9, subpart 9.4. 

(6) An accredited independent verifier 

must maintain, for its employees, and 

ensure the maintenance of, for any 

parties that it employs, professional 

liability insurance, as defined in 31 CFR 

50.5(q), through an insurance provider 

that possesses a financial strength rating 

in the top four categories from either 

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Standard & Poor’s or Moody’s, 

specifically, AAA, AA, A or BBB for 

Standard & Poor’s, and Aaa, Aa, A, or 

Baa for Moody’s. Any entity covered by 

this paragraph must disclose the level of 

professional liability insurance they 

possess when entering into contracts to 

provide verification services pursuant to 

this regulation. 

(d) Requirements for maintenance of 

accreditation status, as follows: 

(1) Accredited independent verifiers 

must meet the requirements of 

§ 62.16475 when providing verification 

services for an authorized account 

representative; and 

(2) The instances specified in 

§ 62.16475(d) are cause for revocation of 

a verifier’s accreditation. 

§ 62.16475 What are the procedures of 

accredited independent verifiers must 

follow to avoid conflict of interest? 

(a) Accredited independent verifiers 

must not provide verification services 

for any eligible resource for which it has 

a conflict of interest (COI), which 

means: 

(1) Accredited independent verifiers 

must have, or have had, no direct or 

indirect financial interest in, or other 

financial relationships with, an eligible 

resource, or any prospective eligible 

resource, for which they seek to provide 

a verification report; 

(2) Accredited independent verifiers 

must have, or have had, no direct or 

indirect organizational or personal 

relationships with an eligible resource, 

that would impact their impartiality in 

assessing the validity and accuracy of 

the information in an eligibility 

application or M&V report; 

(3) Accredited independent verifiers 

must have, or have had, no role in the 

development and implementation of an 

eligible resource for which an 

authorized account representative seeks 

issuance of ERCs, beyond the provision 

of verification services; 

(4) Accredited independent verifiers 

must not be compensated, financially or 

otherwise, directly or indirectly, on the 

basis of the content of its verification 

report (including eligibility approval of 

an eligible resource, the quantified and 

verified MWh in an M&V report, ERC 

issuance, or the number of ERCs issued); 

(5) Accredited independent verifiers 

must not own, buy, sell, or hold ERCs, 

or other financial derivatives related to 

ERCs, or have a financial relationship 

with other parties that own, buy, sell, or 

hold ERCs or other related financial 

derivatives; 

(6) An accredited independent verifier 

must not be incapable of providing an 

impartial verification report for any 

other reason; and 

(7) An accredited independent verifier 

must ensure that the subject of any 

verification report must not have the 

opportunity to review or influence any 

draft or final verification report before 

its submittal to the Administrator, and 

the accredited independent verifier 

must share any drafts of its reports with 

the Administrator at the same time as it 

shares them with the subject of the 

report. 

(b) A contract with an eligible 

resource for the provision of verification 

services will not constitute a COI. 

(c) Verification reports must include 

an attestation by the accredited 

independent verifier that it evaluated 

and disclosed to the Administrator any 

potential COI related to an eligible 

resource. 

(d) Prior to engaging for the provision 

of verification services, an accredited 

independent verifier must demonstrate 

that it has no COI related to the eligible 

resource, as specified in paragraph (a) of 

this section. If a COI is identified for a 

person or persons within an accredited 

independent verifier for a specific 

subject or verification, in accordance 

with paragraphs (e) and (f) of this 

section, then an accredited independent 

verifier may propose to the 

Administrator steps that will be taken to 

eliminate the COI which include 

prohibiting the person or persons with 

the conflict from any involvement in the 

matter subject to the conflict, including 

verification services, access to 

information related to the verification 

services, access to any draft or final 

verification reports, any 

communications with the person(s) 

conducting the verification services. In 

no instance shall an accredited 

independent verifier engage in 

verification services for an eligible 

resource without the approval of the 

Administrator. 

(e) Prior to engaging in verification 

services and writing a verification 

report, an accredited independent 

verifier must disclose to the 

Administrator all information necessary 

for the Administrator to evaluate a 

potential COI (including information 

concerning its ownership, past and 

current clients, related entities, as well 

as any other facts or circumstances that 

have the potential to create a COI). 

(f) Accredited verifiers have an 

ongoing obligation to disclose to the 

Administrator any facts or 

circumstances that may give rise to a 

COI as defined in paragraph (a) of this 

section. 

(g) The Administrator may reject a 

verification report from an accredited 

independent verifier, if the 

Administrator determines that the 

accredited independent verifier has a 

COI as defined in paragraph (a) of this 

section. If the Administrator rejects an 

accredited independent verifier report 

for such reasons, then the eligibility 

application or M&V report submittal 

shall be deemed incomplete and ERCs 

must not be issued pursuant to it. 

§ 62.16480 What is the process for the 

revocation of accreditation status for an 

independent verifier? 

(a) The Administrator may revoke the 

accreditation of an independent verifier 

at any time for cause, including for the 

reasons specified in paragraphs (a)(1) 

through (4) of this section. 

(1) Failure to fully disclose any issues 

that may lead to a COI with respect to 

an eligible resource, or other related 

entity, in accordance with § 62.16475(d) 

through (f). 

(2) The accredited independent 

verifier is no longer qualified to provide 

verification services. 

(3) Negligence in the conduct of 

verification activities, or neglect of 

responsibilities pursuant to the 

requirements of §§ 62.16465, 62.16470, 

and 62.16475. 

(4) Intentional misrepresentation of 

data in a verification report. 

(b) [Reserved] 

Designated Representatives 

§ 62.16485 How are designated 

representatives and alternate designated 

representatives authorized and what role do 

authorized designated representatives and 

alternate designated representatives play? 

(a) Except as provided under 

§ 62.16495, each affected EGU, and each 

eligible resource shall have one and 

only one designated representative, with 

regard to all matters under the CO2 Ratebased Trading Program. 

(1) The designated representative 

shall be selected by an agreement 

binding on the owners and operators of 

the affected EGU and must act in 

accordance with the certification 

statement in § 62.16500(a)(4)(iii). 

(2) Upon and after receipt by the 

Administrator of a complete certificate 

of representation under § 62.16500: 

(i) The designated representative shall 

be authorized and shall represent and, 

by his or her representations, actions, 

inactions, or submissions, legally bind 

each owner and operator of the affected 

EGU in all matters pertaining to the CO2

Rate-based Trading Program, 

notwithstanding any agreement between 

the designated representative and such 

owners and operators; and 

(ii) The owners and operators of the 

affected EGU shall be bound by any 

decision or order issued to the 

designated representative by the 

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Administrator regarding the affected 

EGU. 

(b) Except as provided under 

§ 62.16495, each affected EGU may have 

one and only one alternate designated 

representative, who may act on behalf of 

the designated representative. The 

agreement by which the alternate 

designated representative is selected 

must include a procedure for 

authorizing the alternate designated 

representative to act in lieu of the 

designated representative. 

(1) The alternate designated 

representative shall be selected by an 

agreement binding on the owners and 

operators of the affected EGU and must 

act in accordance with the certification 

statement in § 62.16500(a)(4)(iii). 

(2) Upon and after receipt by the 

Administrator of a complete certificate 

of representation under § 62.16500, 

(i) The alternate designated 

representative must be authorized; 

(ii) Any representation, action, 

inaction, or submission by the alternate 

designated representative shall be 

deemed to be a representation, action, 

inaction, or submission by the 

designated representative; and 

(iii) The owners and operators of the 

affected EGU shall be bound by any 

decision or order issued to the alternate 

designated representative by the 

Administrator regarding any such 

affected EGU. 

(c) Except in this section, §§ 62.16490 

through 62.16510, and § 62.16570, 

whenever the term ‘‘designated 

representative’’ (as distinguished from 

the term ‘‘common designated 

representative’’) is used in this subpart, 

the term shall be construed to include 

the designated representative. 

§ 62.16490 What responsibilities do 

designated representatives and alternate 

designated representatives hold? 

(a) Except as provided under 

§ 62.16510 concerning delegation of 

authority to make submissions, each 

submission under the CO2 Rate-based 

Trading Program must be made, signed, 

and certified by the designated 

representative or alternate designated 

representative for each affected EGU for 

which the submission is made. Each 

such submission must include the 

following certification statement by the 

designated representative or alternate 

designated representative: ‘‘I am 

authorized to make this submission on 

behalf of the owners and operators of 

the affected EGU for which the 

submission is made. I certify under 

penalty of law that I have personally 

examined, and am familiar with, the 

statements and information submitted 

in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(b) The Administrator will accept or 

act on a submission made for an affected 

EGU only if the submission has been 

made, signed, and certified in 

accordance with paragraph (a) of this 

section and § 62.16510. 

§ 62.16495 What are the processes for 

changing designated representatives, 

alternate designated representatives, 

owners and operators, and affected EGUs? 

(a) Changing designated 

representative. The designated 

representative may be changed at any 

time upon receipt by the Administrator 

of a superseding complete certificate of 

representation under § 62.16500. 

Notwithstanding any such change, all 

representations, actions, inactions, and 

submissions by the previous designated 

representative before the time and date 

when the Administrator receives the 

superseding certificate of representation 

shall be binding on the new designated 

representative and the owners and 

operators of the affected EGU. 

(b) Changing alternate designated 

representative. The alternate designated 

representative may be changed at any 

time upon receipt by the Administrator 

of a superseding complete certificate of 

representation under § 62.16500. 

Notwithstanding any such change, all 

representations, actions, inactions, and 

submissions by the previous alternate 

designated representative before the 

time and date when the Administrator 

receives the superseding certificate of 

representation shall be binding on the 

new alternate designated representative, 

the designated representative, and the 

owners and operators of the affected 

EGU. 

(c) Changes in owners and operators. 

(1) In the event an owner or operator of 

an affected EGU is not included in the 

list of owners and operators in the 

certificate of representation under 

§ 62.16500, such owner or operator shall 

be deemed to be subject to and bound 

by the certificate of representation, the 

representations, actions, inactions, and 

submissions of the designated 

representative and any alternate 

designated representative of the affected 

EGU, and the decisions and orders of 

the Administrator, as if the owner or 

operator were included in such list. 

(2) Within 30 days after any change in 

the owners and operators of affected 

EGU, including the addition or removal 

of an owner or operator, the designated 

representative or any alternate 

designated representative must submit a 

revision to the certificate of 

representation under § 62.16500 

amending the list of owners and 

operators to reflect the change. 

(d) Changes in affected EGUs at the 

source. Within 30 days of any change in 

which affected EGUs are located at a 

source (including the addition or 

removal of an affected EGU), the 

designated representative or any 

alternate designated representative must 

submit a certificate of representation 

under § 62.16500 amending the list of 

affected EGUs to reflect the change. 

(1) If the change is the addition of an 

affected EGU that operated (other than 

for purposes of testing by the 

manufacturer before initial installation) 

before being located at the source, then 

the certificate of representation must 

identify, in a format prescribed by the 

Administrator, the entity from whom 

the affected EGU was purchased or 

otherwise obtained (including name, 

address, telephone number, and 

facsimile transmission number (if any)), 

the date on which the affected EGU was 

purchased or otherwise obtained, and 

the date on which the affected EGU 

became located at the source. 

(2) If the change is the removal of an 

affected EGU, then the certificate of 

representation must identify, in a format 

prescribed by the Administrator, the 

entity to which the affected EGU was 

sold or that otherwise obtained the 

affected EGU (including name, address, 

telephone number, and facsimile 

transmission number (if any)), the date 

on which the affected EGU was sold or 

otherwise obtained, and the date on 

which the affected EGU became no 

longer located at the source. 

§ 62.16500 What must be included in a 

certificate of representation? 

(a) A complete certificate of 

representation for a designated 

representative or an alternate designated 

representative must include the 

elements in paragraphs (a)(1) through 

(5) of this section in a format prescribed 

by the Administrator. 

(1) Identification of the affected EGU 

for which the certificate of 

representation is submitted, including 

names, source category and NAICS code 

(or, in the absence of a NAICS code, an 

equivalent code), State, plant code, 

county, latitude and longitude, unit 

identification number and type, 

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identification number and nameplate 

capacity (in MWe, rounded to the 

nearest tenth) of each generator served 

by each such affected EGU, net-summer 

capacity, actual or projected date of 

commencement of commercial 

operation, and a statement of whether 

such affected EGU is located in Indian 

country. If a projected date of 

commencement of commercial 

operation is provided, then the actual 

date of commencement of commercial 

operation must be provided when such 

information becomes available. 

(2) The name, address, email address 

(if any), telephone number, and 

facsimile transmission number (if any) 

of the designated representative and any 

alternate designated representative. 

(3) A list of the owners and operators 

of the affected EGU. 

(4) The following certification 

statements by the designated 

representative and any alternate 

designated representative: 

(i) ‘‘I certify that I was selected as the 

designated representative or alternate 

designated representative, as applicable, 

by an agreement binding on the owners 

and operators of the affected EGU’’; 

(ii) ‘‘I certify that I have all the 

necessary authority to carry out my 

duties and responsibilities under the 

CO2 Rate-based Trading Program on 

behalf of the owners and operators of 

the affected EGU and that each such 

owner and operator shall be fully bound 

by my representations, actions, 

inactions, or submissions and by any 

decision or order issued to me by the 

Administrator regarding the affected 

EGU’’; and 

(iii) ‘‘Where there are multiple 

holders of a legal or equitable title to, or 

a leasehold interest in, an affected EGU, 

or where a utility or industrial customer 

purchases power from an affected EGU 

under a life-of-the-unit, firm power 

contractual arrangement, I certify that: I 

have given a written notice of my 

selection as the ‘designated 

representative’ or ‘alternate designated 

representative’, as applicable, and of the 

agreement by which I was selected to 

each owner and operator of the affected 

EGU; and ERCs and proceeds of 

transactions involving CO2 Rate-based 

Trading Program allowances will be 

deemed to be held or distributed in 

proportion to each holder’s legal, 

equitable, leasehold, or contractual 

reservation or entitlement, except that, 

if such multiple holders have expressly 

provided for a different distribution of 

ERCs by contract, ERCs and proceeds of 

transactions involving CO2 Rate-based 

Trading Program ERCs will be deemed 

to be held or distributed in accordance 

with the contract.’’ 

(5) The signature of the designated 

representative and any alternate 

designated representative and the dates 

signed. 

(b) Unless otherwise required by the 

Administrator, documents of agreement 

referred to in the certificate of 

representation shall not be submitted to 

the Administrator. The Administrator 

shall not be under any obligation to 

review or evaluate the sufficiency of 

such documents, if submitted. 

§ 62.16505 What is the Administrator’s role 

in objections concerning designated 

representatives and alternate designated 

representatives? 

(a) Once a complete certificate of 

representation under § 62.16500 has 

been submitted and received, the 

Administrator will rely on the certificate 

of representation unless and until a 

superseding complete certificate of 

representation under § 62.16500 is 

received by the Administrator. 

(b) Except as provided in paragraph 

(a) of this section, no objection or other 

communication submitted to the 

Administrator concerning the 

authorization, or any representation, 

action, inaction, or submission, of a 

designated representative or alternate 

designated representative shall affect 

any representation, action, inaction, or 

submission of the designated 

representative or alternate designated 

representative or the finality of any 

decision or order by the Administrator 

under the CO2 Rate-based Trading 

Program. 

(c) The Administrator will not 

adjudicate any private legal dispute 

concerning the authorization or any 

representation, action, inaction, or 

submission of any designated 

representative or alternate designated 

representative, including private legal 

disputes concerning the proceeds of 

ERC transfers. 

§ 62.16510 What process must designated 

representatives and alternate designated 

representatives follow to delegate their 

authority? 

(a) A designated representative may 

delegate, to one or more natural persons, 

his or her authority to make an 

electronic submission to the 

Administrator provided for or required 

under this subpart. 

(b) An alternate designated 

representative may delegate, to one or 

more natural persons, his or her 

authority to make an electronic 

submission to the Administrator 

provided for or required under this 

subpart. 

(c) In order to delegate authority to a 

natural person to make an electronic 

submission to the Administrator in 

accordance with paragraph (a) or (b) of 

this section, the designated 

representative or alternate designated 

representative, as appropriate, must 

submit to the Administrator a notice of 

delegation, in a format prescribed by the 

Administrator, that includes the 

following elements: 

(1) The name, address, email address, 

telephone number, and facsimile 

transmission number (if any) of such 

designated representative or alternate 

designated representative; 

(2) The name, address, email address, 

telephone number, and facsimile 

transmission number (if any) of each 

such natural person (referred to in this 

section as an ‘‘agent’’); 

(3) For each such natural person, a list 

of the type or types of electronic 

submissions under paragraph (a) or (b) 

of this section for which authority is 

delegated to him or her; and 

(4) The following certification 

statements by such designated 

representative or alternate designated 

representative: 

(i) ‘‘I agree that any electronic 

submission to the Administrator that is 

made by an agent identified in this 

notice of delegation and of a type listed 

for such agent in this notice of 

delegation and that is made when I am 

a designated representative or alternate 

designated representative, as 

appropriate, and before this notice of 

delegation is superseded by another 

notice of delegation under § 62.16510(d) 

shall be deemed to be an electronic 

submission by me’’; and 

(ii) ‘‘Until this notice of delegation is 

superseded by another notice of 

delegation under § 62.16510(d), I agree 

to maintain an email account and to 

notify the Administrator immediately of 

any change in my email address unless 

all delegation of authority by me under 

§ 62.16510 is terminated.’’ 

(d) A notice of delegation submitted 

under paragraph (c) of this section shall 

be effective, with regard to the 

designated representative or alternate 

designated representative identified in 

such notice, upon receipt of such notice 

by the Administrator and until receipt 

by the Administrator of a superseding 

notice of delegation submitted by such 

designated representative or alternate 

designated representative, as 

appropriate. The superseding notice of 

delegation may replace any previously 

identified agent, add a new agent, or 

eliminate entirely any delegation of 

authority. 

(e) Any electronic submission covered 

by the certification in paragraph (c)(4)(i) 

of this section and made in accordance 

with a notice of delegation effective 

under paragraph (d) of this section shall 

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be deemed to be an electronic 

submission by the designated 

representative or alternate designated 

representative submitting such notice of 

delegation. 

Monitoring, Recordkeeping, Reporting 

§ 62.16515 How are compliance accounts 

and general accounts established and used, 

and how is ERC issuance documentation 

accessed? 

(a) Compliance accounts. (1) Upon 

receipt of a complete certificate of 

representation under § 62.16500, the 

Administrator will establish a 

compliance account for the affected 

EGU for which the certificate of 

representation was submitted, unless 

the affected EGU already has a 

compliance account. The designated 

representative and any alternate 

designated representative of an affected 

EGU shall be the authorized account 

representative and the alternate 

authorized account representative, 

respectively, of the compliance account. 

(2) A compliance account will hold 

ERCs intended for surrender by a 

designated representative when 

demonstrating an affected EGUs 

compliance with a CO2 emission 

standard as applicable in § 62.16420. A 

compliance account may be established 

for a facility with one or more affected 

EGUs, provided that the account 

contains subaccounts for each affected 

EGU within the facility. 

(b) Retirement accounts. (1) A 

retirement account, into which ERCs 

held in a compliance account for an 

affected EGU are surrendered by the 

owner or operator of an affected EGU, 

for use in demonstrating compliance 

with its emission standards. The 

retirement account may only be held by 

the Administrator, and ERCs deposited 

into it are permanently retired. Once an 

ERC is retired, the ERC shall no longer 

be transferable to another account in 

that ERC tracking system or any other 

ERC tracking system. 

(2) [Reserved] 

(c) General accounts—(1) Application 

for a general account. (i) Designated 

representatives of affected EGUs, 

authorized account representatives of 

eligible resources, and any other person 

may apply to open a general account, for 

the purpose of holding and transferring 

ERCs, by submitting to the 

Administrator a complete application 

for a general account. Such application 

must designate one and only one 

authorized account representative and 

may designate one and only one 

alternate authorized account 

representative who may act on behalf of 

the authorized account representative. 

(A) The authorized account 

representative and alternate authorized 

account representative shall be selected 

by an agreement binding on the persons 

who have an ownership interest with 

respect to ERCs held in the general 

account. 

(B) The agreement by which the 

alternate authorized account 

representative is selected must include 

a procedure for authorizing the alternate 

authorized account representative to act 

in lieu of the authorized account 

representative. 

(ii) A complete application for a 

general account must include the 

following elements in a format 

prescribed by the Administrator: 

(A) Name, mailing address, email 

address (if any), telephone number, and 

facsimile transmission number (if any) 

of the authorized account representative 

and any alternate authorized account 

representative; 

(B) An identifying name for the 

general account; 

(C) A list of all persons subject to a 

binding agreement for the authorized 

account representative and any alternate 

authorized account representative to 

represent their ownership interest with 

respect to the ERCs held in the general 

account; 

(D) The following certification 

statement by the authorized account 

representative and any alternate 

authorized account representative: ‘‘I 

certify that I was selected as the 

authorized account representative or the 

alternate authorized account 

representative, as applicable, by an 

agreement that is binding on all persons 

who have an ownership interest with 

respect to ERCs held in the general 

account. I certify that I have all the 

necessary authority to carry out my 

duties and responsibilities under the 

CO2 Rate-based Trading Program on 

behalf of such persons and that each 

such person shall be fully bound by my 

representations, actions, inactions, or 

submissions and by any decision or 

order issued to me by the Administrator 

regarding the general account’’; and 

(E) The signature of the authorized 

account representative and any alternate 

authorized account representative and 

the dates signed. 

(iii) Unless otherwise required by the 

Administrator, documents of agreement 

referred to in the application for a 

general account shall not be submitted 

to the Administrator. The Administrator 

shall not be under any obligation to 

review or evaluate the sufficiency of 

such documents, if submitted. 

(2) Authorization of authorized 

account representative and alternate 

authorized account representative. (i) 

Upon receipt by the Administrator of a 

complete application for a general 

account under paragraph (c)(1) of this 

section, the Administrator will establish 

a general account for the person or 

persons for whom the application is 

submitted, and upon and after such 

receipt by the Administrator: 

(A) The authorized account 

representative of the general account 

shall be authorized and shall represent 

and, by his or her representations, 

actions, inactions, or submissions, 

legally bind each person who has an 

ownership interest with respect to ERCs 

held in the general account in all 

matters pertaining to the CO2 Rate-based 

Trading Program, notwithstanding any 

agreement between the authorized 

account representative and such person; 

(B) Any alternate authorized account 

representative shall be authorized, and 

any representation, action, inaction, or 

submission by any alternate authorized 

account representative shall be deemed 

to be a representation, action, inaction, 

or submission by the authorized account 

representative; and 

(C) Each person who has an 

ownership interest with respect to ERCs 

held in the general account shall be 

bound by any decision or order issued 

to the authorized account representative 

or alternate authorized account 

representative by the Administrator 

regarding the general account. 

(ii) Except as provided in paragraph 

(c)(5) of this section concerning 

delegation of authority to make 

submissions, each submission 

concerning the general account must be 

made, signed, and certified by the 

authorized account representative or 

any alternate authorized account 

representative for the persons having an 

ownership interest with respect to ERCs 

held in the general account. Each such 

submission must include the following 

certification statement by the authorized 

account representative or any alternate 

authorized account representative: ‘‘I 

am authorized to make this submission 

on behalf of the persons having an 

ownership interest with respect to the 

ERCs held in the general account. I 

certify under penalty of law that I have 

personally examined, and am familiar 

with, the statements and information 

submitted in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

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including the possibility of fine or 

imprisonment.’’ 

(iii) Except in this section, whenever 

the term ‘‘authorized account 

representative’’ is used in this subpart, 

the term shall be construed to include 

the authorized account representative or 

any alternate authorized account 

representative. 

(3) Changing authorized account 

representative and alternate authorized 

account representative; changes in 

persons with ownership interest. 

(i) The authorized account 

representative of a general account may 

be changed at any time upon receipt by 

the Administrator of a superseding 

complete application for a general 

account under paragraph (c)(1) of this 

section. Notwithstanding any such 

change, all representations, actions, 

inactions, and submissions by the 

previous authorized account 

representative before the time and date 

when the Administrator receives the 

superseding application for a general 

account shall be binding on the new 

authorized account representative and 

the persons with an ownership interest 

with respect to the ERCs in the general 

account. 

(ii) The alternate authorized account 

representative of a general account may 

be changed at any time upon receipt by 

the Administrator of a superseding 

complete application for a general 

account under paragraph (c)(1) of this 

section. Notwithstanding any such 

change, all representations, actions, 

inactions, and submissions by the 

previous alternate authorized account 

representative before the time and date 

when the Administrator receives the 

superseding application for a general 

account shall be binding on the new 

alternate authorized account 

representative, the authorized account 

representative, and the persons with an 

ownership interest with respect to the 

ERCs in the general account. 

(iii)(A) In the event a person having 

an ownership interest with respect to 

ERCs in the general account is not 

included in the list of such persons in 

the application for a general account, 

such person shall be deemed to be 

subject to and bound by the application 

for a general account, the 

representation, actions, inactions, and 

submissions of the authorized account 

representative and any alternate 

authorized account representative of the 

account, and the decisions and orders of 

the Administrator, as if the person were 

included in such list. 

(B) Within 30 days after any change 

in the persons having an ownership 

interest with respect to ERCs in the 

general account, including the addition 

or removal of a person, the authorized 

account representative or any alternate 

authorized account representative must 

submit a revision to the application for 

a general account amending the list of 

persons having an ownership interest 

with respect to the ERCs in the general 

account to include the change. 

(4) Objections concerning authorized 

account representative and alternate 

authorized account representative. 

(i) Once a complete application for a 

general account under paragraph (c)(1) 

of this section has been submitted and 

received, the Administrator will rely on 

the application unless and until a 

superseding complete application for a 

general account under paragraph (c)(1) 

of this section is received by the 

Administrator. 

(ii) Except as provided in paragraph 

(c)(4)(i) of this section, no objection or 

other communication submitted to the 

Administrator concerning the 

authorization, or any representation, 

action, inaction, or submission of the 

authorized account representative or 

any alternate authorized account 

representative of a general account shall 

affect any representation, action, 

inaction, or submission of the 

authorized account representative or 

any alternate authorized account 

representative or the finality of any 

decision or order by the Administrator 

under the CO2 Rate-based Trading 

Program. 

(iii) The Administrator will not 

adjudicate any private legal dispute 

concerning the authorization or any 

representation, action, inaction, or 

submission of the authorized account 

representative or any alternate 

authorized account representative of a 

general account, including private legal 

disputes concerning the proceeds of 

ERCs transfers. 

(5) Delegation by authorized account 

representative and alternate authorized 

account representative. 

(i) An authorized account 

representative of a general account may 

delegate, to one or more natural persons, 

his or her authority to make an 

electronic submission to the 

Administrator provided for or required 

under this subpart. 

(ii) An alternate authorized account 

representative of a general account may 

delegate, to one or more natural persons, 

his or her authority to make an 

electronic submission to the 

Administrator provided for or required 

under this subpart. 

(iii) In order to delegate authority to 

a natural person to make an electronic 

submission to the Administrator in 

accordance with paragraph (c)(5)(i) or 

(ii) of this section, the authorized 

account representative or alternate 

authorized account representative, as 

appropriate, must submit to the 

Administrator a notice of delegation, in 

a format prescribed by the 

Administrator, that includes the 

following elements: 

(A) The name, address, email address, 

telephone number, and facsimile 

transmission number (if any) of such 

authorized account representative or 

alternate authorized account 

representative; 

(B) The name, address, email address, 

telephone number, and facsimile 

transmission number (if any) of each 

such natural person (referred to in this 

section as an ‘‘agent’’); 

(C) For each such natural person, a 

list of the type or types of electronic 

submissions under paragraph (c)(5)(i) or 

(ii) of this section for which authority is 

delegated to him or her; 

(D) The following certification 

statement by such authorized account 

representative or alternate authorized 

account representative: ‘‘I agree that any 

electronic submission to the 

Administrator that is made by an agent 

identified in this notice of delegation 

and of a type listed for such agent in 

this notice of delegation and that is 

made when I am an authorized account 

representative or alternate authorized 

representative, as appropriate, and 

before this notice of delegation is 

superseded by another notice of 

delegation under § 62.16515(c)(5)(iv) 

shall be deemed to be an electronic 

submission by me’’; and 

(E) The following certification 

statement by such authorized account 

representative or alternate authorized 

account representative: ‘‘Until this 

notice of delegation is superseded by 

another notice of delegation under 

§ 62.16515(c)(5)(iv), I agree to maintain 

an email account and to notify the 

Administrator immediately of any 

change in my email address unless all 

delegation of authority by me under 

§ 62.16515(c)(5) is terminated.’’ 

(iv) A notice of delegation submitted 

under paragraph (c)(5)(iii) of this section 

shall be effective, with regard to the 

authorized account representative or 

alternate authorized account 

representative identified in such notice, 

upon receipt of such notice by the 

Administrator and until receipt by the 

Administrator of a superseding notice of 

delegation submitted by such 

authorized account representative or 

alternate authorized account 

representative, as appropriate. The 

superseding notice of delegation may 

replace any previously identified agent, 

add a new agent, or eliminate entirely 

any delegation of authority. 

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(v) Any electronic submission covered 

by the certification in paragraph 

(c)(5)(iii)(D) of this section and made in 

accordance with a notice of delegation 

effective under paragraph (c)(5)(iv) of 

this section shall be deemed to be an 

electronic submission by the authorized 

account representative or alternate 

authorized account representative 

submitting such notice of delegation. 

(6) Closing a general account. (i) The 

authorized account representative or 

alternate authorized account 

representative of a general account may 

submit to the Administrator a request to 

close the account. Such request must 

include a correctly submitted ERC 

transfer under § 62.16525 for any ERCs 

in the account to one or more other 

ATCS accounts. 

(ii) If a general account has no ERC 

transfers to or from the account for a 12- 

month period or longer and does not 

contain any ERCs, then the 

Administrator may notify the authorized 

account representative for the account 

that the account will be closed 30 days 

after the notice is sent. The account will 

be closed after the 30-day period unless, 

before the end of the 30-day period, the 

Administrator receives a correctly 

submitted ERC transfer under 

§ 62.16525 to the account or a statement 

submitted by the authorized account 

representative or alternate authorized 

account representative demonstrating to 

the satisfaction of the Administrator 

good cause as to why the account 

should not be closed. 

(d) Account identification. The 

Administrator will assign a unique 

identifying number to each account 

established under paragraphs (a) 

through (c) of this section. 

(e) Responsibilities of authorized 

account representative and alternate 

authorized account representative. After 

the establishment of a compliance 

account or general account, the 

Administrator will accept or act on a 

submission pertaining to the account, 

including, but not limited to, 

submissions concerning the deduction 

or transfer of ERCs in the account, only 

if the submission has been made, 

signed, and certified in accordance with 

§ 62.16490(a) and § 62.16510 or 

paragraphs (c)(2)(ii) and (5) of this 

section. 

(f) ERC identification information. 

The Administrator will assign to each 

ERC issued in the EPA ERC tracking 

system a unique serial identifier that 

begins with the two digit postal 

abbreviation of the State in which it was 

issued and includes the year it was 

issued, and the eligible resource 

category that generated it. 

(g) Records supporting ERC issuance. 

The Administrator will maintain in the 

EPA ERC tracking system records of, for 

each ERC, all of the following: 

(1) Account holder names and 

information; 

(2) Authorized account representative 

name and information; 

(3) Qualifying eligible resource 

identification number, name, State, and 

contact information including street 

address, mailing address, phone 

number, and email; 

(4) Category of qualifying eligible 

resource, according to the categories 

specified in § 62.16435(a)(4); 

(5) The date the qualifying eligible 

resource commenced generation or 

saving of energy; 

(6) Individual ERCs, each with a 

unique serial identifier that meets the 

requirements of paragraph (f) of this 

section; 

(7) Records of ERC transfers among 

accounts, including the date of transfer 

and the accounts involved in the 

transfer; 

(8) The date an ERC was surrendered 

for a compliance demonstration; 

(9) Date an ERC was retired by the 

regulatory body; and 

(10) Each eligibility application, 

EM&V plan, M&V report, and 

verification report associated with the 

issuance of each specific ERC, and each 

regulatory approval and any 

documentation that supports the 

issuance of each ERC by the 

Administrator. 

(h) Access to records supporting ERC 

issuance. The Administrator will 

provide in the EPA ERC tracking system 

access and functionality to allow each 

ERC to be traceable by the public to the 

records listed in paragraph (g) of this 

section. This information will be 

accessible via an electronic, internetbased portal in the ERC tracking system 

searchable by, at a minimum, each 

eligible resource, affected EGU, eligible 

resource category, and ERC. 

(i) Reports. The Administrator will 

provide in the EPA ERC tracking system 

electronic, internet-based access to 

enable the generation of at least the 

following reports, [for as long as this 

regulation is effective] [in perpetuity]: 

(1) Account activity reports. By each 

account holder, reports based on records 

of their account activity, including the 

information listed in paragraph (g) of 

this section; 

(2) Public reports. By the public, 

reports that include: All of the 

information listed in paragraph (g) of 

this section; a list of all registered 

account holders in the ERC tracking 

system, including compliance accounts 

and general accounts; a list of all 

eligible resources (including access to 

all documentation for such eligible 

resources); a list of all accredited 

independent verifiers; and aggregate 

ERC activity statistics on at least an 

annual basis, for at least the following: 

Issuance of ERCs, transfers among 

accounts, transfers in or out of the ERC 

tracking system to/from another 

approved ERC tracking system (if 

relevant), and ERC retirements. The ERC 

tracking system shall provide this 

functionality for as long as this 

regulation is effective; and 

(3) EPA reports. For the EPA and state 

regulators, the information listed in 

paragraph (g) of this section and any 

other information regarding ERC 

issuance, transfer, surrender, and 

retirement for purpose of compliance 

with this regulation. 

(j) Interactions with other ERC 

tracking systems. If approved in 

connection with a State plan, then an 

ERC tracking system may provide for 

transfers of ERCs to/from another ERC 

tracking system approved in connection 

with a State plan by the EPA, or provide 

for transfers of ERCs to/from an EPAadministered ERC tracking system used 

to administer a federal plan. To transfer 

ERCs to or from an EPA-administered 

ERC tracking system, the state ERC 

tracking system must be approved under 

subpart UUUU of part 60 of this chapter 

for such use by the EPA. 

§ 62.16525 How must transfers of ERCs be 

submitted? 

(a) An authorized account 

representative seeking recordation of an 

ERC transfer must submit the transfer to 

the Administrator. 

(b) An ERC transfer is correctly 

submitted if: 

(1) The transfer includes the following 

elements, in a format prescribed by the 

Administrator: 

(i) The account numbers established 

by the Administrator for both the 

transferor and transferee accounts; 

(ii) The serial number of each ERC 

that is in the transferor account and is 

to be transferred; and 

(iii) The name and signature of the 

authorized account representative of the 

transferor account and the date signed; 

and 

(2) When the Administrator attempts 

to record the transfer, the transferor 

account includes each ERC identified by 

serial number in the transfer. 

§ 62.16530 When will ERC transfers be 

recorded? 

(a) Except as provided in paragraph 

(b) of this section, within five business 

days of receiving an ERC transfer that is 

correctly submitted under § 62.16525, 

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the Administrator will record an ERC 

transfer by moving each ERC from the 

transferor account to the transferee 

account as specified in the transfer. 

(b) An ERC transfer to or from a 

compliance account that is submitted 

for recordation after the allowance 

transfer deadline for a compliance 

period and that includes any ERCs 

allocated for any compliance period 

before such allowance transfer deadline 

will not be recorded until after the 

Administrator completes the deductions 

from such compliance account under 

§ 62.16535 for the compliance period 

immediately before such allowance 

transfer deadline. 

(c) Where an ERC transfer is not 

correctly submitted under § 62.16525, 

the Administrator will not record such 

transfer. 

(d) Within five business days of 

recordation of an ERC transfer under 

paragraphs (a) and (b) of the section, the 

Administrator will notify the authorized 

account representatives of both the 

transferor and transferee accounts. 

(e) Within 10 business days of receipt 

of an ERC transfer that is not correctly 

submitted under § 62.16525, the 

Administrator will notify the authorized 

account representatives of both accounts 

subject to the transfer of: 

(1) A decision not to record the 

transfer; and 

(2) The reasons for such nonrecordation. 

§ 62.16535 How will deductions for 

compliance with a CO2 emission standard 

occur? 

For affected EGUs subject to the 

emission standards listed in Table 1 of 

this subpart, the owner or operator of an 

affected EGU must demonstrate 

compliance with its CO2 emission 

standard in accordance with 

§ 62.16420(c) and incorporate ERCs as 

listed in paragraphs (a) through (f) of 

this section. 

(a) Availability for deduction for 

compliance. ERCs are available to be 

deducted from a compliance account 

and used for compliance with an 

affected EGU’s CO2 emissions standard 

for a compliance period only if the 

ERCs: 

(1) Were allocated for a year in such 

compliance period or a prior 

compliance period; and 

(2) Are held in the affected EGU’s 

compliance account as of the allowance 

transfer deadline for such compliance 

period. 

(b) Deductions for compliance. After 

the recordation, in accordance with 

§ 62.16530, of ERC transfers submitted 

by the ERC transfer deadline for a 

compliance period, the Administrator 

will deduct from each affected EGU’s 

compliance account ERCs available 

under paragraph (a) of this section in 

order to determine whether the affected 

EGU meets the CO2 emission standard 

for such compliance period, as follows: 

(1) Until the amount of ERCs 

deducted and subsequently added to the 

total MWh generated by the affected 

EGU adjusts the affected EGU’s CO2

emission rate to equal the CO2 emission 

standard for such compliance period; or 

(2) If there are insufficient ERCs to 

complete the deductions in paragraph 

(b)(1) of this section, until no more ERCs 

available under paragraph (a) of this 

section remain in the compliance 

account. 

(c) Identification of ERCs by serial 

number. The authorized account 

representative for an affected EGU’s 

compliance account may request that 

specific ERCs, identified by serial 

number, in the compliance account be 

deducted for emissions or excess 

emissions for a compliance period in 

accordance with paragraph (b) or (e) of 

this section. In order to be complete, 

such request must be submitted to the 

Administrator by the ERC transfer 

deadline for such compliance period 

and include, in a format prescribed by 

the Administrator, the identification of 

the affected EGU and the appropriate 

serial numbers. 

(d) First-in, first-out. The 

Administrator will deduct ERCs under 

paragraph (b) or (e) of this section from 

the affected EGU’s compliance account 

in accordance with a complete request 

under paragraph (c)(1) of this section or, 

in the absence of such request or in the 

case of identification of an insufficient 

amount of ERCs in such request, on a 

first-in, first-out accounting basis. 

(e) Deductions for exceeding the 

emission standard. After making the 

deductions for compliance under 

paragraph (b) of this section for a 

compliance period in a year in which 

the affected EGU has exceeded its CO2

emission standard, the Administrator 

will deduct from the affected EGU’s 

compliance account an amount of ERCs, 

allocated for a compliance period in a 

prior year or the compliance period in 

the year of the excess emissions or in 

the immediately following year, equal to 

two times the number of ERCs of the 

affected EGU’s excess emissions. 

(f) Recordation of deductions. The 

Administrator will record in the 

appropriate compliance account all 

deductions from such an account under 

paragraphs (b) and (e) of this section. 

§ 62.16540 What monitoring requirements 

must I comply with? 

(a) You must follow the requirements 

described in paragraphs (a)(1) through 

(8) of this section to monitor emissions 

and net energy output at your affected 

EGU. 

(1) The owner of operator of an 

affected EGU required to meet an 

emission standard must prepare a 

monitoring plan in accordance with the 

applicable provisions in § 75.53(g) and 

(h) of this chapter, unless such a plan 

is already in place under another 

program that requires CO2 mass 

emissions to be monitored and reported 

according to part 75 of this chapter. 

(2) Each compliance period shall 

include only ‘‘valid operating hours’’ in 

the compliance period, i.e., operating 

hours for which: 

(i) ‘‘Valid data’’ (as defined in 

§ 62.16570) are obtained for all of the 

parameters used to determine the hourly 

CO2 mass emissions (lbs). For the 

purposes of this subpart, substitute data 

recorded under part 75 of this chapter 

are not considered to be valid data; and 

(ii) The corresponding hourly net 

energy output value is also valid data 

(Note: for hours with no useful output, 

zero is considered to be a valid value). 

(3) The owner or operator of an 

affected EGU must measure and report 

the hourly CO2 mass emissions (lbs) 

from each affected unit using the 

procedures in paragraphs (a)(3)(i) 

through (vii) of this section, except as 

provided in paragraph (a)(4) of this 

section. 

(i) The owner or operator of an 

affected EGU must install, certify, 

operate, maintain, and calibrate a CO2

continuous emissions monitoring 

system (CEMS) to directly measure and 

record CO2 concentrations in the 

affected EGU exhaust gases emitted to 

the atmosphere and an exhaust gas flow 

rate monitoring system according to 

§ 75.10(a)(3)(i) of this chapter. As an 

alternative to direct measurement of 

CO2 concentration, the owner or 

operator of an affected EGU may use 

data from a certified oxygen (O2) 

monitor to calculate hourly average CO2

concentrations, in accordance with 

§ 75.10(a)(3)(iii) of this chapter. If CO2

concentration is measured on a dry 

basis, then you must also install, certify, 

operate, maintain, and calibrate a 

continuous moisture monitoring system, 

according to § 75.11(b) of this chapter. 

Alternatively, you may either use an 

appropriate fuel-specific default 

moisture value from § 75.11(b) or submit 

a petition to the Administrator under 

§ 75.66 of this chapter for a site-specific 

default moisture value. 

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(ii) For each ‘‘valid operating hour’’, 

calculate the hourly CO2 mass emission 

rate (tons/hr), either from Equation F–11 

in Appendix F to part 75 of this chapter 

(if CO2 concentration is measured on a 

wet basis), or by following the 

procedure in section 4.2 of Appendix F 

to part 75 of this chapter (if CO2

concentration is measured on a dry 

basis). 

(iii) Next, multiply each hourly CO2

mass emission rate by the affected EGU 

or stack operating time in hours (as 

defined in § 72.2 of this chapter), to 

convert it to tons of CO2. Multiply the 

result by 2000 lb/ton to convert it to lb. 

(iv) The hourly CO2 tons/hr values 

and affected EGU (or stack) operating 

times used to calculate CO2 mass 

emissions are required to be recorded 

under § 75.57(e) of this chapter and 

must be reported electronically under 

§ 75.64(a)(6). You must use these data to 

calculate the hourly CO2 mass 

emissions. 

(v) Sum all of the hourly CO2 mass 

emissions values that were calculated 

according to procedures specified in 

paragraph (a)(3)(ii) of this section over 

the entire compliance period. 

(vi) For each continuous monitoring 

system used to determine the CO2 mass 

emissions from an affected EGU, the 

monitoring system must meet the 

applicable certification and quality 

assurance procedures in § 75.20 of this 

chapter and Appendices A and B to part 

75 of this chapter. 

(vii) The owner operator of an affected 

EGU must use only unadjusted exhaust 

gas volumetric flow rates to determine 

the hourly CO2 mass emissions from the 

affected EGU; the owner or operator of 

an affected EGU must not apply the bias 

adjustment factors described in section 

7.6.5 of Appendix A to part 75 of this 

chapter to the exhaust gas flow rate 

data. 

(4) The owner or operator of an 

affected EGU that exclusively combusts 

liquid fuel and/or gaseous fuel may, as 

an alternative to complying with 

paragraph (a)(3) of this section, 

determine the hourly CO2 mass 

emissions according to paragraphs 

(a)(4)(i) through (vi) of this section. 

(i) Implement the applicable 

procedures in appendix D to part 75 of 

this chapter to determine hourly 

affected EGU heat input rates (MMBtu/ 

h), based on hourly measurements of 

fuel flow rate and periodic 

determinations of the gross calorific 

value (GCV) of each fuel combusted. 

(ii) For each measured hourly heat 

input rate, use Equation G–4 in 

Appendix G to part 75 of this chapter to 

calculate the hourly CO2 mass emission 

rate (tons/hr). 

(iii) For each valid operating hour (as 

defined in paragraph (a)(2) of this 

section, determine the hourly CO2 mass 

emission rate (tons/hr) using the 

procedures specified in paragraph 

(a)(4)(ii) of this section and multiply it 

by the affected EGU or stack operating 

time in hours (as defined in § 72.2 of 

this chapter), to convert to tons of CO2. 

Then, multiply the result by 2000 lb/ton 

to convert to lb. 

(iv) The hourly CO2 tons/hr values 

and affected EGU (or stack) operating 

times used to calculate CO2 mass 

emissions are required to be recorded 

under § 75.57(e) of this chapter and 

must be reported electronically under 

§ 75.64(a)(6). You must use these data to 

calculate the hourly CO2 mass 

emissions. 

(v) Sum all of the hourly CO2 mass 

emissions values that were calculated 

according to procedures specified in 

paragraph (a)(4)(iii) of this section over 

the entire compliance period. 

(vi) The owner or operator of an 

affected EGU may determine sitespecific carbon-based F-factors (Fc) 

using Equation F–7b in section 3.3.6 of 

appendix F to part 75 of this chapter, 

and may use these Fc values in the 

emissions calculations instead of using 

the default Fc values in the Equation G– 

4 nomenclature. 

(5) The owner or operator of an 

affected EGU must install, calibrate, 

maintain, and operate a sufficient 

number of watt meters to continuously 

measure and record on an hourly basis 

net electric output. Measurements must 

be performed using 0.2 accuracy class 

electricity metering instrumentation and 

calibration procedures as specified 

under ANSI Standards No. C12.20. 

Further, the owner or operator of an 

affected EGU that is a combined heat 

and power facility must install, 

calibrate, maintain and operate 

equipment to continuously measure and 

record on an hourly basis useful thermal 

output and, if applicable, mechanical 

output, which are used with net electric 

output to determine net energy output. 

The owner or operator must calculate 

net energy output according to 

paragraph (a)(5)(i) of this section. 

(i) For each valid operating hour of a 

compliance period that was used in 

paragraph (a)(3) or (4) of this section to 

calculate the total CO2 mass emissions, 

you must determine Pnet (the 

corresponding hourly net energy output 

in MWh) according to the procedures in 

paragraphs (a)(5)(i)(A) and (B) of this 

section, as appropriate for the type of 

affected EGU(s). For an operating hour 

in which a valid CO2 mass emissions 

value is determined according to 

paragraph (a)(3) or (4) of this section, if 

there is no gross or net electrical output, 

but there is mechanical or useful 

thermal output, then you must still 

determine the net energy output for that 

hour. In addition, for an operating hour 

in which a valid CO2 mass emissions 

value is determined according to 

paragraph (a)(3) or (4) of this section, 

but there is no (i.e., zero) gross 

electrical, mechanical, or useful thermal 

output, you must use that hour in the 

compliance determination. For hours or 

partial hours where the gross electric 

output is equal to or less than the 

auxiliary loads, net electric output shall 

be counted as zero for this calculation. 

(A) Calculate Pnet for your affected 

EGU using the following equation. All 

terms in the equation must be expressed 

in units of megawatt-hours (MWh). To 

convert each hourly net energy output 

value reported under part 75 of this 

chapter to MWh, multiply by the 

corresponding EGU or stack operating 

time. 

Where: 

Pnet = Net energy output of your affected EGU 

for each valid operating hour (as defined 

in paragraph (a)(2) of this section) in 

MWh. 

(Pe)ST = Electric energy output plus 

mechanical energy output (if any) of 

steam turbines in MWh. 

(Pe)CT = Electric energy output plus 

mechanical energy output (if any) of 

stationary combustion turbine(s) in 

MWh. 

(Pe)IE = Electric energy output plus 

mechanical energy output (if any) of 

your affected EGU’s integrated 

equipment that provides electricity or 

mechanical energy to the affected EGU or 

auxiliary equipment in MWh. 

(Pe)A = Electric energy used for any auxiliary 

loads in MWh. 

(Pt)PS = Useful thermal output of steam 

(measured relative to SATP conditions as 

defined in § 62.16570, as applicable) that 

is used for applications that do not 


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generate additional electricity, produce 

mechanical energy output, or enhance 

the performance of the affected EGU. 

This is calculated using the equation 

specified in paragraph (a)(5)(i)(B) of this 

section in MWh. 

(Pt)HR = Non steam useful thermal output 

(measured relative to SATP conditions as 

defined in § 62.16570, as applicable) 

from heat recovery that is used for 

applications other than steam generation 

or performance enhancement of the 

affected EGU in MWh. 

(Pt)IE = Useful thermal output (relative to 

SATP conditions, as applicable as 

defined in § 62.16570) from any 

integrated equipment is used for 

applications that do not generate 

additional steam, electricity, produce 

mechanical energy output, or enhance 

the performance of the affected EGU in 

MWh. 

TDF = Electric Transmission and Distribution 

Factor of 0.95 for a combined heat and 

power affected EGU where at least on an 

annual basis 20.0 percent of the total net 

energy output consists of electric or 

direct mechanical output and 20.0 

percent of the total net energy output 

consists of useful thermal output on a 

12-operating month rolling average basis, 

or 1.0 for all other affected EGUs. 

(B) If applicable to your affected EGU 

(for example, for combined heat and 

power), then you must calculate (Pt)PS

using the following equation: 

Where: 

(Pt)ps = Useful thermal output of steam 

(measured relative to SATP conditions as 

defined in § 62.16570, as applicable) that 

is used for applications that do not 

generate additional electricity, produce 

mechanical energy output, or enhance 

the performance of the affected EGU. 

Qm = Measured steam flow in kilograms (kg) 

(or pounds (lb)) for the operating hour. 

H = Enthalpy of the steam at measured 

temperature and pressure (relative to 

SATP conditions as defined in 

§ 62.16570 or the energy in the 

condensate return line, as applicable) in 

Joules per kilogram (J/kg) (or Btu/lb). 

CF = Conversion factor of 3.6 × 10 9 J/MWh 

or 3.413 × 10 6 Btu/MWh. 

(C) Sum all of the values of Pnet over 

the entire compliance period. Then, 

divide the total CO2 mass emissions 

from paragraph (a)(3)(v) or (a)(4)(v) of 

this section, as applicable, by the sum 

of the Pnet values to determine the CO2

emission rate (lb/net MWh) for the 

compliance period. 

(ii) [Reserved] 

(6) In accordance with § 60.13(g) of 

this chapter, if two or more affected 

EGUs implementing the continuous 

emissions monitoring provisions in 

paragraph (a)(2) of this section share a 

common exhaust gas stack and are 

subject to the same emission standard, 

then the owner or operator may monitor 

the hourly CO2 mass emissions at the 

common stack in lieu of monitoring 

each EGU separately. If an owner or 

operator of an affected EGU chooses this 

option, then the hourly net electric 

output for the common stack must be 

the sum of the hourly net electric output 

of the individual affected EGUs and the 

operating time must be expressed as 

‘‘stack operating hours’’ (as defined in 

§ 72.2 of this chapter). 

(7) In accordance with § 60.13(g) of 

this chapter, if the exhaust gases from 

an affected EGU implementing the 

continuous emissions monitoring 

provisions in paragraph (a)(3)(i) of this 

section are emitted to the atmosphere 

through multiple stacks (or if the 

exhaust gases are routed to a common 

stack through multiple ducts and you 

elect to monitor in the ducts), then the 

hourly CO2 mass emissions and the 

‘‘stack operating time’’ (as defined in 

§ 72.2 of this chapter) at each stack or 

duct must be monitored separately. In 

this case, the owner or operator of an 

affected EGU must determine 

compliance with an applicable emission 

standard by summing the CO2 mass 

emissions measured at the individual 

stacks or ducts and dividing by the net 

energy output for the affected EGU. 

(8) If two or more affected EGUs serve 

a common electric generator, then you 

must apportion the combined hourly net 

energy output to the individual affected 

EGUs according to the fraction of the 

total steam load contributed by each 

EGU. Alternatively, if the affected EGUs 

are identical, then you may apportion 

the combined hourly net electrical load 

to the individual EGUs according to the 

fraction of the total heat input 

contributed by each EGU. 

(b) [Reserved] 

§ 62.16545 May I bank CO2 ERCs for future 

use or transfer? 

(a) An ERC may be banked for future 

use or transfer in a compliance account 

or a general account in accordance with 

paragraph (b) of this section. 

(b) Any ERC that is held in a 

compliance account or a general 

account will remain in such account 

unless and until the ERC is deducted or 

transferred under §§ 62.16530, 

62.16535, 62.16550, or 62.16565. 

§ 62.16550 How does the Administrator 

process account errors? 

The Administrator may, at his or her 

sole discretion and on his or her own 

motion, correct any error in any ATCS 

account. Within 10 business days of 

making such correction, the 

Administrator will notify the authorized 

account representative for the account. 

§ 62.16555 What are my reporting, 

notification and submission requirements? 

You must prepare and submit reports 

according to paragraphs (a) through (g) 

of this section, as applicable. 

(a)(1) You must meet all applicable 

reporting requirements and submit 

reports as required under subpart G of 

part 75 of this chapter and you must 

include the following information, as 

applicable in the quarterly reports: 

(i) The percentage of valid operating 

hours in each quarter described 

§ 62.16540(a)(2) (i.e., the total number of 

valid operating hours) in that period 

divided by the total number of operating 

hours in that period, multiplied by 100 

percent); 

(ii) The hourly CO2 mass emission 

rate values (tons/hr) and unit (or stack) 

operating times, (as monitored and 

reported according to part 75 of this 

chapter), for each valid operating hour 

in the compliance period; 

(iii) The net electric output and the 

net energy output (Pnet) values for each 

valid operating hour in the compliance 

period; 

(iv) The calculated CO2 mass 

emissions (lb) for each valid operating 

hour in the compliance period; 

(v) The sum of the hourly net energy 

output values and the sum of the hourly 

CO2 mass emissions values, for all of the 

valid operating hours in the compliance 

period; 

(vi) ERC replacement generation (if 

any), properly justified (see paragraph 

(a)(1)(viii) of this section); 

(vii) The calculated CO2 mass 

emission rate for the compliance period 

(lb/net MWh); and 

(viii) If the report covers the final 

quarter of a compliance period, then 

you must include the CO2 emission 

standard (as identified in Table 1 of this 

subpart) with which your affected EGU 

must comply, your CO2 emission rate 

calculated according to § 62.16420(c), 

and if an affected EGU is complying 

with an emission standard by using 

ERCs, then the designated 

representative must also include in the 

report a list of all unique ERC serial 

numbers retired in the compliance 

period, and, for each ERC, the date an 

ERC was surrendered and retired and 

eligible resource identification 

information sufficient to demonstrates 

that it meets the requirements of 

§ 62.16435 and qualifies to be issued 

ERCs (including location, type of 

qualifying generation or savings, date 

commenced generating or saving, and 

date of generation or savings for which 

the ERC was issued). 


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(b) If any required monitoring system 

has not been provisionally certified by 

the applicable date on which emissions 

data reporting is required to begin under 

paragraph (a) of this section, then the 

maximum (or in some cases, minimum) 

potential value for the parameter 

measured by the monitoring system 

shall be reported until the required 

certification testing is successfully 

completed, in accordance with § 75.4(j) 

of this chapter, § 75.37(b) of this 

chapter, or section 2.4 of appendix D to 

part 75 of this chapter (as applicable). 

Operating hours in which CO2 mass 

emission rates are calculated using 

maximum potential values are not 

‘‘valid operating hours’’ (as defined in 

§ 62.16540(a)), and shall not be used in 

the compliance determinations. 

(c) The designated representative of 

each affected EGU at the facility must 

make all submissions required under 

the CO2 Rate-based Trading Program, 

except as provided in § 62.16510. This 

requirement does not change, create an 

exemption from, or otherwise affect the 

responsible official submission 

requirements under a title V operating 

permit program in parts 70 and 71 of 

this chapter. 

(d) You must submit all electronic 

reports required under paragraph (a) of 

this section using the Emissions 

Collection and Monitoring Plan System 

(ECMPS) Client Tool provided by the 

Clean Air Markets Division in the Office 

of Atmospheric Programs of EPA. 

(e) For affected EGUs under this 

subpart that are not in the Acid Rain 

Program, you must also meet the 

reporting requirements and submit 

reports as required under subpart G of 

part 75 of this chapter, to the extent that 

those requirements and reports provide 

applicable data for the compliance 

demonstrations required under this 

subpart. 

(f) If your affected EGU captures CO2

to meet the applicable emission 

standard, then you must report in 

accordance with the requirements of 

part 98, subpart PP, of this chapter and 

either: 

(1) Report in accordance with the 

requirements of part 98, subpart RR, of 

this chapter, if injection occurs on-site; 

or 

(2) Transfer the captured CO2 to an 

affected EGU or facility that reports in 

accordance with the requirements of 

part 98, subpart RR, of this chapter, if 

injection occurs off-site. 

(g) You must prepare and submit 

notifications specified in § 75.61 of this 

chapter, as applicable to your affected 

EGUs. 

§ 62.16560 What are my recordkeeping 

requirements? 

(a) The owner or operator of each 

affected EGU must maintain the records, 

as described in paragraph (a)(1) of this 

section, for at least 5 years following the 

date of each compliance period, 

occurrence, measurement, maintenance, 

corrective action, report, or record. 

(1) Unless otherwise provided, the 

owner or operator of an affected EGU 

must maintain the following records on 

site for at least 2 years after the date of 

each compliance period, compliance 

true-up period, occurrence, 

measurement, maintenance, corrective 

action, report, or record, whichever is 

latest, according to § 60.7 of this 

chapter. The owner or operator of an 

affected EGU may maintain the records 

off site and electronically for the 

remaining year(s). This period may be 

extended for cause, at any time before 

the end of 5 years, in writing by the 

Administrator. 

(i) The certificate of representation 

under § 62.16500 for the designated 

representative for each affected EGU 

and all documents that demonstrate the 

truth of the statements in the certificate 

of representation; provided that the 

certificate and documents must be 

retained on site at the affected EGU 

beyond such 5-year period until such 

certificate of representation and 

documents are superseded because of 

the submission of a new certificate of 

representation under § 62.16500 

changing the designated representative. 

(ii) All emissions monitoring 

information, in accordance with this 

subpart. 

(iii) Copies of all reports, compliance 

certifications, documents, data files, 

calculations and methods, other 

submissions and all records made or 

required under, or to demonstrate 

compliance with an affected EGU’s 

emission standard under § 62.16420 and 

any other requirements of the CO2 Ratebased Trading Program. 

(iv) Data that are required to be 

recorded by part 75, subpart F, of this 

chapter. 

(v) Data with respect to any ERCs 

generated by the affected EGU or used 

by the affected EGU in its compliance 

demonstration including the 

information in paragraphs (a)(1)(v)(A) 

and (B) of this section. 

(A) All documents related to any 

ERCs used in a compliance 

demonstration, including each 

eligibility application, EM&V plan, M&V 

report, and independent verifier 

verification report associated with the 

issuance of each specific ERC, and each 

regulatory approval and any 

documentation that supports the 

issuance of each ERC by the 

Administrator. 

(B) All records and reports relating to 

the surrender and retirement of ERCs for 

compliance with this regulation, 

including the date each individual ERC 

with a unique serial identification 

number was surrendered and/or retired. 

(2) [Reserved] 

(b) [Reserved] 

§ 62.16565 What actions may the 

Administrator take on submissions? 

(a) The Administrator may review and 

conduct independent audits concerning 

any submission under the CO2 Ratebased Trading Program and make 

appropriate adjustments of the 

information in the submission. 

(b) The Administrator may deduct 

ERCs from or transfer ERCs to a 

compliance account, based on the 

information in a submission, as adjusted 

under paragraph (a) of this section, and 

record such deductions and transfers. 

Definitions 

§ 62.16570 What definitions apply to this 

subpart? 

The terms used in this subpart have 

the meanings set forth in this section as 

follows: 

Acid Rain Program means a multistate SO2 and NOX air pollution control 

and emission reduction program 

established by the Administrator under 

title IV of the Clean Air Act and parts 

72 through 78 of this chapter. 

Administrator means the 

Administrator of the United States 

Environmental Protection Agency or his 

or her delegate, or the authorized state 

official under an approved state plan 

that incorporates this subpart. 

Affected electric generating unit or 

Affected EGU means any steam 

generating unit, IGCC, or stationary 

combustion turbine that meets the 

applicability requirements in 

§§ 60.5840(b) and 60.5845 of this 

chapter. An affected EGU is not an 

eligible resource. 

Allowable CO2 emission rate means, 

for an affected EGU, the most stringent 

State or federal CO2 emission rate limit 

(in lb/MWh or, if in lb/mmBtu, 

converted to lb/MWh by multiplying it 

by the affected EGU’s heat rate in 

mmBtu/MWh) that is applicable to the 

affected EGU and covers the longest 

averaging period not exceeding 1 year. 

Allowance system means a control 

program under which the owner or 

operator of each affected EGU is 

required to hold an authorization for 

each specified unit of carbon dioxide 

emitted from that facility during a 

specified period and which limits the 

total amount of such authorizations 

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available to be held for carbon dioxide 

for a specified period and allows the 

transfer of such authorizations not used 

to meet the authorization-holding 

requirement. 

Allowance Tracking and Compliance 

System (ATCS) means the system by 

which the Administrator records 

allocations, deductions, and transfers of 

ERCs under the CO2 Rate-based Trading 

Program. Such allowances are allocated, 

recorded, held, deducted, or transferred 

only as whole ERCs. 

Alternate designated representative 

means, for a CO2 Rate-based Trading 

affected EGU and each affected EGU at 

the facility, the natural person who is 

authorized by the owners and operators 

of the affected EGU and all such affected 

EGUs at the affected EGU, in accordance 

with this subpart, to act on behalf of the 

designated representative in matters 

pertaining to the CO2 Rate-based 

Trading Program. If the affected EGU is 

also subject to the Acid Rain Program, 

TR NOX Annual Trading Program, TR 

NOX Ozone Season Trading Program, 

TR SO2 Group 1 Trading Program, or TR 

SO2 Group 2 Trading Program, then this 

natural person shall be the same natural 

person as the alternate designated 

representative, as defined in the 

respective program. 

Annual capacity factor means the 

ratio between the actual heat input to an 

EGU during a calendar year and the 

potential heat input to the EGU had it 

been operated for 8,760 hours during a 

calendar year at the base load rating. 

Also see capacity factor. 

Authorized account representative 

means, for a general account, the natural 

person who is authorized, in accordance 

with this subpart, to transfer and 

otherwise dispose of ERCs held in the 

general account and, for a CO2 Ratebased Trading Program affected EGU’s, 

the designated representative of the 

affected EGU is the authorized account 

representative. 

Automated data acquisition and 

handling system or DAHS means the 

component of the continuous emission 

monitoring system, or other emissions 

monitoring system approved for use 

under this subpart, designed to interpret 

and convert individual output signals 

from pollutant concentration monitors, 

flow monitors, diluent gas monitors, 

and other component parts of the 

monitoring system to produce a 

continuous record of the measured 

parameters in the measurement units 

required by this subpart. 

Base load rating means the maximum 

amount of heat input (fuel) that an EGU 

can combust on a steady state basis, as 

determined by the physical design and 

characteristics of the EGU at ISO 

conditions. For a stationary combustion 

turbine, base load rating includes the 

heat input from duct burners. 

Baseline means the electricity use that 

would have occurred without 

implementation of a specific EE 

measure. 

Biomass means biologically based 

material that is living or dead (e.g., 

trees, crops, grasses, tree litter, roots) 

above and belowground, and available 

on a renewable or recurring basis. 

Materials that are biologically based 

include non-fossilized, biodegradable 

organic material originating from 

modern or contemporarily grown plants, 

animals, or microorganisms (including 

plants, products, byproducts and 

residues from agriculture, forestry, and 

related activities and industries, as well 

as the non-fossilized and biodegradable 

organic fractions of industrial and 

municipal wastes, including gases and 

liquids recovered from the 

decomposition of non-fossilized and 

biodegradable organic material). 

Boiler means an enclosed fossil- or 

other-fuel-fired combustion device used 

to produce heat and to transfer heat to 

recirculating water, steam, or other 

medium. 

Business day means a day that does 

not fall on a weekend or a federal 

holiday. 

Capacity factor means, as used for the 

output based set-aside, the ratio of the 

net electrical energy produced by a 

generating unit for the period of time 

considered to the electrical energy that 

could have been produced at 

continuous net summer capacity during 

the same period. 

Certifying official means a natural 

person who is: 

(1) For a corporation, a president, 

secretary, treasurer, or vice-president of 

the corporation in charge of a principal 

business function or any other person 

who performs similar policy- or 

decision-making functions for the 

corporation; 

(2) For a partnership or sole 

proprietorship, a general partner or the 

proprietor respectively; or 

(3) For a local government entity or 

State, federal, or other public agency, a 

principal executive officer or ranking 

elected official. 

Clean Air Act means the Clean Air 

Act, 42 U.S.C. 7401, et seq. 

CO2 emissions limitation means the 

tonnage of CO2 emissions authorized in 

a compliance period in a given year by 

the CO2 allowances available for 

deduction for the affected EGU under 

§ 62.16535(a) for such compliance 

period. 

CO2 Rate-Based Trading Program 

means a multi-state CO2 air pollution 

control and emission reduction program 

established in accordance with this 

subpart and subpart UUUU of part 60 of 

this chapter (including such a program 

that is revised in a State plan or state 

allowance distribution methodology, or 

by the Administrator under subpart 

UUUU of part 60 of this chapter), as a 

means of controlling CO2 emissions. 

Coal means the definition as defined 

in subpart TTTT of part 60 of this 

chapter. 

Combined cycle unit means an 

electric generating unit that uses a 

stationary combustion turbine from 

which the heat from the turbine exhaust 

gases is recovered by a heat recovery 

steam generating unit to generate 

additional electricity. 

Combined heat and power unit or 

CHP unit, (also known as 

‘‘cogeneration’’) means an electric 

generating unit that uses a steamgenerating unit or stationary combustion 

turbine to simultaneously produce both 

electric (or mechanical) and useful 

thermal output from the same primary 

energy affected EGU. 

Common practice baseline or CPB 

means a baseline derived based on a 

default technology or condition that 

would have been in place at the time of 

implementation of an EE measure in the 

absence of the EE measure (for example, 

the standard or market-average or preexisting equipment that a typical 

consumer/building owner would have 

continued to use or would have 

installed at the time of project 

implementation in a given 

circumstance, such as a given building 

type, EE program type or delivery 

mechanism, and geographic region). 

Common stack means a single flue 

through which emissions from two or 

more units are exhausted. 

Compliance account means an 

Allowance Transfer and Compliance 

System account, established by the 

Administrator for an affected EGU 

under this subpart, in which any ERC 

allocations to the affected EGUs at the 

affected EGU are recorded and in which 

are held any CO2 allowances available 

for use for a compliance period in a 

given year in complying with the 

affected EGU’s CO2 emission standard 

in accordance with §§ 62.16420 and 

62.16535. 

Compliance period means the multiyear periods starting January 1 of the 

first calendar year of the period, except 

as provided in § 62.16420(c)(3), and 

ending on December 31 of the last 

calendar year, inclusive: 

(1) Compliance Period 1 means the 

period of 3 calendar years from January 

1, 2022 to December 31, 2024; 

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(2) Compliance Period 2 means the 

period of 3 calendar years from January 

1, 2025 to December 31, 2027; and 

(3) Compliance Period 3 means the 

period of 2 calendar years from January 

1, 2028 to December 31, 2029. 

Conservation voltage regulation (or 

reduction) (CVR) means an EE measure 

that produces electricity savings by 

reducing (or regulating) voltage at the 

electrical feeder level. 

Continuous emission monitoring 

system or CEMS means the equipment 

required under this subpart to sample, 

analyze, measure, and provide, by 

means of readings recorded at least once 

every 15 minutes and using an 

automated data acquisition and 

handling system (DAHS), a permanent 

record of CO2 emissions, stack gas 

volumetric flow rate, stack gas moisture 

content, and O2 concentration (as 

applicable), in a manner consistent with 

part 75 of this chapter and 

§ 62.16540(a)(3). The following systems 

are the principal types of continuous 

emission monitoring systems: 

(1) A flow monitoring system, 

consisting of a stack flow rate monitor 

and an automated data acquisition and 

handling system and providing a 

permanent, continuous record of stack 

gas volumetric flow; 

(2) A moisture monitoring system, as 

defined in § 75.11(b)(2) of this chapter 

and providing a permanent, continuous 

record of the stack gas moisture content, 

in percent H2O; 

(3) A CO2 monitoring system, 

consisting of a CO2 pollutant 

concentration monitor (or an O2 monitor 

plus suitable mathematical equations 

from which the CO2 concentration is 

derived) and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of CO2 emissions, in percent CO2; 

and 

(4) An O2 monitoring system, 

consisting of an O2 concentration 

monitor and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of O2, in percent O2. 

Control area operator means an 

electric system or systems, bounded by 

interconnection metering and telemetry, 

capable of controlling generation to 

maintain its interchange schedule with 

other control areas and contributing to 

frequency regulation of the 

interconnection. 

Deemed savings means estimates of 

average annual electricity savings for a 

single unit of an installed demand-side 

EE measure that: has been developed 

from data sources (such as prior 

metering studies) and analytical 

methods widely considered acceptable 

for the measure; and is applicable to the 

situation and conditions in which the 

measure is implemented. Individual 

parameters or calculation methods also 

can be deemed, including EUL values. 

Common sources of deemed savings 

values are previous evaluations and 

studies that involved actual 

measurements and analyses. Deemed 

savings values are applicable for 

specific demand-side EE measures. A 

single deemed savings value may not be 

used for a program as a whole, nor for 

a multi-measure project, because of the 

degree of variation in how systems are 

used in different building types or 

market segments. 

Demand-side energy efficiency or 

demand-side EE means an installed 

piece of equipment or system, a 

modification of existing equipment or 

system, or a strategy intended to affect 

consumer electricity-use behavior, that 

results in a reduction in electricity use 

(in MWh) at an end-use facility, 

premises, or equipment connected to 

the electricity grid. Demand-side EE is 

implemented through energy efficiency 

activities, projects, programs or 

measures 

Derate means a decrease in the 

available capacity of an electric 

generating unit, due to a system or 

equipment modification or to 

discounting a portion of a generating 

unit’s capacity for planning purposes. 

Designated representative means, for 

a CO2 Rate-based Trading affected EGU 

and each affected EGU at the affected 

EGU, the natural person who is 

authorized by the owners and operators 

of the affected EGU and all such affected 

EGUs at the affected EGU, in accordance 

with this subpart, to represent and 

legally bind each owner and operator in 

matters pertaining to the CO2 Rate-based 

Trading Program. If the CO2 Rate-based 

Trading affected EGU is also subject to 

the Acid Rain Program, TR NOX Annual 

Trading Program, TR NOX Ozone 

Season Trading Program, TR SO2 Group 

1 Trading Program, or TR SO2 Group 2 

Trading Program, then this natural 

person shall be the same natural person 

as the designated representative, as 

defined in the respective program. 

Design efficiency means the rated 

overall net efficiency (e.g., electric plus 

thermal output) on a higher heating 

value basis of the EGU at the base load 

rating and ISO conditions. 

Distillate oil means the definition as 

defined in subpart TTTT of part 60 of 

this chapter. 

Effective useful life (EUL) means the 

duration over which electricity savings 

from an EE measure occur, reported in 

years. EUL values are typically specific 

to individual EE projects but also may 

be specified by an EE program. 

Electricity savings means the savings 

that results from a change in electricity 

use resulting from the implementation 

of demand-side EE. 

Eligible resource means a resource 

that meets the requirements of 

§ 62.16435 and has been registered with 

the EPA-administered ERC tracking 

system or an ERC tracking system 

approved in a State plan by the EPA. An 

eligible resource is not an affected EGU. 

EM&V plan means an evaluation 

measurement and verification plan that 

meets the requirements of § 62.16455. 

Emissions means air pollutants 

exhausted from an affected EGU into the 

atmosphere; emissions must be 

measured, recorded, and reported to the 

Administrator by the designated 

representative, and as modified by the 

Administrator: 

(1) In accordance with this subpart; 

and 

(2) With regard to a period before the 

affected EGU or facility is required to 

measure, record, and report such air 

pollutants in accordance with this 

subpart, in accordance with part 75 of 

this chapter. 

Emission rate credit (ERC) means a 

tradable compliance instrument that 

meets the requirements of § 60.5790(c) 

of this chapter. 

ERC deduction or deduct ERCs means 

the permanent withdrawal of ERCs by 

the Administrator from a compliance 

account (e.g., in order to account for 

compliance with the applicable CO2

emission standard). 

Energy efficiency program or EE 

program means organized activities 

sponsored and funded by a particular 

entity to promote the adoption of one or 

more EE project or EE measure for the 

purpose of reducing electricity use. 

Energy efficiency project or EE project 

means a combination of multiple 

technologies, energy-use practices or 

behaviors implemented at a single 

facility or premises for the purpose of 

reducing electricity use; EE projects may 

be implemented as part of an EE 

program or as an independent privatelyfunded action. 

Energy efficiency measure or EE 

measure means a single technology, 

energy-use practice or behavior that, 

once implemented or adopted, reduces 

electricity use of a particular end-use, 

facility, or premises; EE measures may 

be implemented as part of an EE 

program or as an independent privatelyfunded action. 

ERC held or hold ERCs means the 

ERCs treated as included in an ATCS 

account as of a specified point in time 

because at that time they: 

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(1) Have been recorded by the 

Administrator in the account or 

transferred into the account by a 

correctly submitted, but not yet 

recorded, ERC transfer in accordance 

with this subpart; and 

(2) Have not been transferred out of 

the account by a correctly submitted, 

but not yet recorded, ERC transfer in 

accordance with this subpart. 

ERC transfer deadline means, for a 

compliance period in a given year, 

midnight of November 1 (if it is a 

business day), or midnight of the first 

business day thereafter (if November 1 

is not a business day), immediately after 

such compliance period and is the 

deadline by which an ERC transfer must 

be submitted for recordation in a 

affected EGU’s compliance account in 

order to be available for use in 

complying with the affected EGU’s CO2

emission standard for such compliance 

period in accordance with §§ 62.16420 

and 62.16535. 

Essential generating characteristics 

means any characteristic that affects the 

eligibility of the qualifying energy 

generating resource for generating ERCs 

pursuant to this regulation, including 

the type of resource. 

Excess emissions means any ton of 

emissions from the affected EGUs at an 

affected EGU during a compliance 

period that exceeds the CO2 emissions 

limitation for the affected EGU for such 

compliance period. 

Existing state program, requirement, 

or measure means, in the context of a 

State plan, a regulation, requirement, 

program, or measure administered by a 

state, utility, or other entity that is 

currently established. This may include 

a regulation or other legal requirement 

that includes past, current, and future 

obligations, or current programs and 

measures that are in place and are 

anticipated to be continued or expanded 

in the future, in accordance with 

established plans. An existing state 

program, requirement, or measure may 

have past, current, and future impacts 

on EGU CO2 emissions. 

Facility means all buildings, 

structures, or installations located in 

one or more contiguous or adjacent 

properties under common control of the 

same person or persons. This definition 

does not change or otherwise affect the 

definition of ‘‘major source’’, ‘‘stationary 

source’’, or ‘‘source’’ as set forth and 

implemented in a title V operating 

permit program or any other program 

under the Clean Air Act. 

Final compliance period means a 

compliance period within the final 

period, each being 2 calendar years 

(with a calendar year beginning on 

January 1 and ending on December 31), 

and the first final compliance period 

beginning on January 1, 2030 and 

ending December 31, 2031. 

Final period means the period that 

begins on January 1, 2030 and continues 

thereafter. The final period is comprised 

of final compliance periods, each of 

which is 2 calendar years (with a 

calendar year beginning on January 1 

and ending on December 31). 

Fossil fuel means the definition as 

defined in subpart TTTT of part 60 of 

this chapter. 

Fossil-fuel-fired means, with regard to 

an affected EGU, combusting any 

amount of fossil fuel. 

Gaseous fuel means the definition as 

defined in subpart TTTT of part 60 of 

this chapter. 

General account means an ATCS 

account established under this subpart 

that is not a compliance account. 

Generator means a device that 

produces electricity. 

Gross electrical output means, for an 

affected EGU, electricity made available 

for use, including any such electricity 

used in the power production process 

(which process includes, but is not 

limited to, any on-site processing or 

treatment of fuel combusted at the 

affected EGU and any on-site emission 

controls). 

GS–ERC means an ERC issued for net 

energy output MWh of gas shift to, but 

which may not be used for compliance 

by, an affected EGU that is a stationary 

combustion turbine. Aside from this 

restriction on use for compliance, GS– 

ERCs are subject to all other provisions 

of this subpart related to ERCs. 

Heat input means, for an affected EGU 

for a specified period of time, the 

product (in mmBtu/time) of the gross 

calorific value of the fuel (in mmBtu/lb) 

fed into the affected EGU multiplied by 

the fuel feed rate (in lb of fuel/time), as 

measured, recorded, and reported to the 

Administrator by the designated 

representative and as modified by the 

Administrator in accordance with this 

subpart and excluding the heat derived 

from preheated combustion air, 

recirculated flue gases, or exhaust. 

Heat input rate means, for an affected 

EGU, the amount of heat input (in 

mmBtu) divided by affected EGU 

operating time (in hr) or, for an affected 

EGU and a specific fuel, the amount of 

heat input attributed to the fuel (in 

mmBtu) divided by the affected EGU 

operating time (in hr) during which the 

affected EGU combusts the fuel. 

Heat rate means, for an affected EGU, 

the affected EGU’s maximum design 

heat input (in Btu/hr), divided by the 

product of 1,000,000 Btu/mmBtu and 

the affected EGU’s maximum hourly 

load. 

Heat recovery steam generating unit 

(HRSG) means a unit in which hot 

exhaust gases from the combustion 

turbine engine are routed in order to 

extract heat from the gases and generate 

useful output. Heat recovery steam 

generating units can be used with or 

without duct burners. 

Indian country means ‘‘Indian 

country’’ as defined in 18 U.S.C. 1151. 

Integrated gasification combined 

cycle facility or IGCC facility means a 

combined cycle facility that is designed 

to burn fuels containing 50 percent (by 

heat input) or more solid-derived fuel 

not meeting the definition of natural gas 

plus any integrated equipment that 

provides electricity or useful thermal 

output to either the affected facility or 

auxiliary equipment. The Administrator 

may waive the 50 percent solid-derived 

fuel requirement during periods of the 

gasification system construction, startup 

and commissioning, shutdown, or 

repair. No solid fuel is directly burned 

in the unit during operation. 

Interim period means the period of 8 

calendar years from January 1, 2022 to 

December 31, 2029. The interim period 

is comprised of three compliance 

periods, compliance period 1, 

compliance period 2, and compliance 

period 3. 

ISO conditions means 288 Kelvin 

(15 °C), 60 percent relative humidity 

and 101.3 kilopascals pressure. 

Liquid fuel means the definition as 

defined in subpart TTTT of part 60 of 

this chapter. 

M&V report means a monitoring and 

verification report that meets the 

requirements of § 62.16460. 

Maximum design heat input means, 

for an affected EGU, the maximum 

amount of fuel per hour (in Btu/hr) that 

the affected EGU is capable of 

combusting on a steady state basis as of 

the initial installation of the affected 

EGU as specified by the manufacturer of 

the affected EGU. 

Mechanical output means the useful 

mechanical energy that is not used to 

operate the affected facility, generate 

electricity and/or thermal output, or to 

enhance the performance of the affected 

facility. Mechanical energy measured in 

horsepower hour should be converted 

into MWh by multiplying it by 745.7 

then dividing by 1,000,000. 

Monitoring system means any 

monitoring system that meets the 

requirements of this subpart, including 

a continuous emission monitoring 

system, an alternative monitoring 

system, or an excepted monitoring 

system under part 75 of this chapter. 

Nameplate capacity means, starting 

from the initial installation of a 

generator, the maximum electrical 

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generating output (in MWe, rounded to 

the nearest tenth) that the generator is 

capable of producing on a steady state 

basis and during continuous operation 

(when not restricted by seasonal or 

other deratings) of such installation as 

specified by the manufacturer of the 

generator or, starting from the 

completion of any subsequent physical 

change in the generator resulting in an 

increase in the maximum electrical 

generating output that the generator is 

capable of producing on a steady state 

basis and during continuous operation 

(when not restricted by seasonal or 

other deratings), such increased 

maximum amount (in MWe, rounded to 

the nearest tenth) of such completion as 

specified by the person conducting the 

physical change. 

Natural gas means the definition as 

defined in subpart TTTT of part 60 of 

this chapter. 

Net-electric output means the amount 

of gross generation the generator(s) 

produce (including, but not limited to, 

output from steam turbine(s), 

combustion turbine(s), and gas 

expander(s)), as measured at the 

generator terminals, less the electricity 

used to operate the plant (i.e., auxiliary 

loads); such uses include fuel handling 

equipment, pumps, fans, pollution 

control equipment, other electricity 

needs, and transformer losses as 

measured at the transmission side of the 

step up transformer (e.g., the point of 

sale). 

Net energy output means: 

(1) The net electric or mechanical 

output from the affected facility, plus 

100 percent of the useful thermal output 

measured relative to SATP conditions 

that is not used to generate additional 

electric or mechanical output or to 

enhance the performance of the affected 

EGU (e.g., steam delivered to an 

industrial process for a heating 

application); and 

(2) For combined heat and power 

facilities where at least 20.0 percent of 

the total net energy output consists of 

electric or direct mechanical output and 

at least 20.0 percent of the total net 

energy output consists of useful thermal 

output on a 12-operating month rolling 

average basis, the net electric or 

mechanical output from the affected 

EGU divided by 0.95, plus 100 percent 

of the useful thermal output (e.g., steam 

delivered to an industrial process for a 

heating application). 

Net summer capacity means the 

maximum output, commonly expressed 

in megawatts (MW), that generating 

equipment can supply to system load, as 

demonstrated by a multi-hour test, at 

the time of summer peak demand 

(period of June 1 through September 

30.) This output reflects a reduction in 

capacity due to electricity use for station 

service or auxiliaries. 

Operate or operation means, with 

regard to an affected EGU, to combust 

fuel. 

Operator means, for a CO2 Rate-based 

Trading affected EGU or an affected 

EGU at an affected EGU respectively, 

any person who operates, controls, or 

supervises an affected EGU at the 

affected EGU or the affected EGU and 

includes, but is not limited to, any 

holding company, utility system, or 

plant manager of such affected EGU or 

affected EGU. 

Owner means, for a CO2 Rate-based 

Trading affected EGU or an affected 

EGU at an affected EGU respectively, 

any of the following persons: 

(1) Any holder of any portion of the 

legal or equitable title in an affected 

EGU at the affected EGU or the affected 

EGU; 

(2) Any holder of a leasehold interest 

in an affected EGU at the affected EGU 

or the affected EGU, provided that, 

unless expressly provided for in a 

leasehold agreement, ‘‘owner’’ shall not 

include a passive lessor, or a person 

who has an equitable interest through 

such lessor, whose rental payments are 

not based (either directly or indirectly) 

on the revenues or income from such 

affected EGU; and 

(3) Any purchaser of power from a 

affected EGU at the affected EGU or the 

affected EGU under a life-of-the-unit, 

firm power contractual arrangement. 

Permanently retired means, with 

regard to an affected EGU, that an 

affected EGU is unavailable for service 

and the affected EGU’s owners and 

operators: have taken on as enforceable 

obligations in the operating permit that 

covers the affected EGU the conditions 

of § 62.16415; or rescinded or otherwise 

terminated all permits required for 

construction or operation of the affected 

EGU under the Clean Air Act. 

Cessations in operations that do not 

meet this definition do not constitute 

permanent retirements. 

Petroleum means the definition as 

defined in subpart TTTT of part 60 of 

this chapter. 

Qualified biomass means a biomass 

feedstock that is demonstrated to qualify 

as a method to control increases of CO2

levels in the atmosphere. 

Random error means errors occurring 

by chance that may cause electricity 

savings values to be inconsistently 

overestimated or underestimated, and 

may result from a change in electricity 

use due to unaccounted-for factors that 

affect electricity use. The magnitude of 

random error can be quantified based on 

the variations observed across different 

units. 

Receive or receipt of means, when 

referring to the Administrator, to come 

into possession of a document, 

information, or correspondence 

(whether sent in hard copy or by 

authorized electronic transmission), as 

indicated in an official log, or by a 

notation made on the document, 

information, or correspondence, by the 

Administrator in the regular course of 

business. 

Recordation, record, or recorded 

means, with regard to ERCs, the moving 

of ERCs by the Administrator into, out 

of, or between ATCS accounts, for 

purposes of allocation, transfer, or 

deduction. 

Reference method means any direct 

test method of sampling and analyzing 

for an air pollutant as specified in 

§ 75.22 of this chapter. 

Replacement, replace, or replaced 

means, with regard to an affected EGU, 

the demolishing of an affected EGU, or 

the permanent retirement and 

permanent disabling of an affected EGU, 

and the construction of another affected 

EGU (the replacement affected EGU) to 

be used instead of the demolished or 

retired affected EGU (the replaced 

affected EGU). 

Solid fuel means the definition as 

defined in subpart TTTT of part 60 of 

this chapter. 

Solid waste incineration unit means a 

stationary, fossil-fuel-fired boiler or 

stationary, fossil-fuel-fired combustion 

turbine that is a ‘‘solid waste 

incineration unit’’ as defined in section 

129(g)(1) of the Clean Air Act. 

Standard ambient temperature and 

pressure (SATP) conditions means 

298.15 Kelvin (25 °C, 77 °F) and 100.0 

kilopascals (14.504 psi, 0.987 atm) 

pressure. The enthalpy of water at SATP 

conditions is 50 Btu/lb. 

State agent means an entity acting on 

behalf of the State, with the legal 

authority of the State. 

State measures means measures that 

the State adopts and implements as a 

matter of state law. Such measures are 

enforceable only per state law, and are 

not included in and codified as part of 

the federally enforceable State plan. 

Stationary combustion turbine means 

all equipment, including but not limited 

to the turbine engine, the fuel, air, 

lubrication and exhaust gas systems, 

control systems (except emissions 

control equipment), heat recovery 

system, fuel compressor, heater, and/or 

pump, post-combustion emissions 

control technology, and any ancillary 

components and sub-components 

comprising any simple cycle stationary 

combustion turbine, any combined 

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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Proposed Rules 65115 

cycle combustion turbine, and any 

combined heat and power combustion 

turbine based system plus any 

integrated equipment that provides 

electricity or useful thermal output to 

the combustion turbine engine, heat 

recovery system or auxiliary equipment. 

Stationary means that the combustion 

turbine is not self-propelled or intended 

to be propelled while performing its 

function. It may, however, be mounted 

on a vehicle for portability. If a 

stationary combustion turbine burns any 

solid fuel directly then it is considered 

a steam generating unit. 

Steam generating unit means any 

furnace, boiler, or other device used for 

combusting fuel and producing steam 

(nuclear steam generators are not 

included) plus any integrated 

equipment that provides electricity or 

useful thermal output to the affected 

facility or auxiliary equipment. 

Submit or serve means to send or 

transmit a document, information, or 

correspondence to the person specified 

in accordance with the applicable 

regulation: 

(1) In person; 

(2) By United States Postal Service; or 

(3) By other means of dispatch or 

transmission and delivery; 

(4) Provided that compliance with any 

‘‘submission’’ or ‘‘service’’ deadline 

shall be determined by the date of 

dispatch, transmission, or mailing and 

not the date of receipt. 

Systematic error means inaccuracies 

in the same direction, causing electricity 

savings values to be consistently either 

overestimated or underestimated, and 

may result from factors such as incorrect 

assumptions, a methodological issue, or 

a flawed reporting system. 

Transmission and distribution loss 

means the difference between the 

quantity of electricity that serves a load 

(measured at the busbar of the 

generator) and the actual electricity use 

at the final distribution location 

(measured at the on-site meter). 

Transmission and distribution 

measures or T&D measures means EE 

measures intended to improve the 

efficiency of the electrical transmission 

and distribution system by decreasing 

electricity loses on the system. 

Unit operating day means, with 

regard to an affected EGU, a calendar 

day in which the affected EGU combusts 

any fuel. 

Unit operating hour or hour of unit 

operation means, with regard to an 

affected EGU, an hour in which the 

affected EGU combusts any fuel. 

Uprate means an increase in available 

electric generating unit power capacity 

due to a system or equipment 

modification. 

Useful thermal output means the 

thermal energy made available for use in 

any heating application (e.g., steam 

delivered to an industrial process for a 

heating application, including thermal 

cooling applications) that is not used for 

electric generation, mechanical output 

at the affected EGU, to directly enhance 

the performance of the affected EGU 

(e.g., economizer output is not useful 

thermal output, but thermal energy used 

to reduce fuel moisture is considered 

useful thermal output), or to supply 

energy to a pollution control device at 

the affected EGU. Useful thermal output 

for affected EGU(s) with no condensate 

return (or other thermal energy input to 

the affected EGU(s)) or where measuring 

the energy in the condensate (or other 

thermal energy input to the affected 

EGU(s)) would not meaningfully impact 

the emission rate calculation is 

measured against the energy in the 

thermal output at SATP conditions. 

Affected EGU(s) with meaningful energy 

in the condensate return (or other 

thermal energy input to the affected 

EGU) must measure the energy in the 

condensate and subtract that energy 

relative to SATP conditions from the 

measured thermal output. 

Utility power distribution system 

means the portion of an electricity grid 

owned or operated by a utility and 

dedicated to delivering electricity to 

customers. 

Valid data means quality-assured data 

generated by continuous monitoring 

systems that are installed, operated, and 

maintained according to part 75 of this 

chapter. For CEMS, the initial 

certification requirements in § 75.20 of 

this chapter and appendix A to part 75 

of this chapter must be met before 

quality-assured data are reported under 

this subpart; for on-going quality 

assurance, the daily, quarterly, and 

semiannual/annual test requirements in 

sections 2.1, 2.2, and 2.3 of appendix B 

to part 75 of this chapter must be met 

and the data validation criteria in 

sections 2.1.5, 2.2.3, and 2.3.2 of 

appendix B to part 75 of this chapter 

apply. For fuel flow meters, the initial 

certification requirements in section 

2.1.5 of appendix D to part 75 of this 

chapter must be met before qualityassured data are reported under this 

subpart (except for qualifying 

commercial billing meters under section 

2.1.4.2 of appendix D), and for on-going 

quality assurance, the provisions in 

section 2.1.6 of appendix D to part 75 

of this chapter apply (except for 

qualifying commercial billing meters). 

Verification report means a report that 

meets the requirements of § 62.16465. 

Waste-to-Energy means a process or 

unit (e.g., solid waste incineration unit) 

that recovers energy from the 

conversion or combustion of waste 

stream materials, such as municipal 

solid waste, to generate electricity and/ 

or heat. 

§ 62.16575 What measurements, 

abbreviations, and acronyms apply to this 

subpart? 

The measurements, abbreviations, and 

acronyms used in this subpart are 

defined as follows: 

ADR—alternated designated representative 

Btu—British thermal unit 

CPP—clean power plan 

CO2—carbon dioxide 

COI—conflict of interest 

CVR—conservative voltage regulation 

DR—designated representative 

EE—energy efficiency 

EGU—electric generating unit 

EM&V—evaluation, measurement, and 

verification 

ERC—emission rate credit 

GCV—gross calorific value 

GJ—giga joule 

H2O—water 

hr—hour 

IGCC—integrated gasification combined 

cycle 

kg—kilogram 

kW—kilowatt electrical 

kWh—kilowatt hour 

lb—pound 

M&V—measurement and verification 

mmBtu—million Btu 

MWe—megawatt electrical 

MWh—megawatt hour 

T&D—transmission and distribution 

O2—oxygen 

PSD—prevention of significant deterioration 

yr—year 

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65116 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Proposed Rules 

TABLE 1 TO SUBPART NNN OF PART 62—CO2 EMISSION STANDARDS (POUNDS OF CO2 PER NET MWH) 

Compliance period 

Affected steam 

generating unit or 

integrated gasification 

combined cycle 

(IGCC) emission 

standards 

Affected stationary 

combustion turbine 

emission standard 

Compliance Period 1 (2022–2024) .................................................................................................. 1,671 877 

Compliance Period 2 (2025–2027) .................................................................................................. 1,500 817 

Compliance Period 3 (2028–2029) .................................................................................................. 1,380 784 

Final Compliance Periods ................................................................................................................ 1,305 771 

TABLE 2 TO SUBPART NNN OF PART

62—INCREMENTAL GENERATION

FACTOR FOR EMISSION RATE CREDITS (DIMENSIONLESS) 

Compliance period 

Incremental 

Generation 

Factor 

Compliance Period 1 (2022– 

2024) ................................. .22 

Compliance Period 2 (2025– 

2027) ................................. .32 

Compliance Period 3 (2028– 

2029) ................................. .28 

Final Compliance Periods .... .26 

PART 78—APPEAL PROCEDURES 

■ 6. The authority citation for Part 78 

continues to read as follows: 

Authority: 42 U.S.C. 7401, 7403, 7410, 

7411, 7426, 7601, and 7651 et seq. 

■ 7. Section 78.1 is amended by revising 

paragraph (a)(1) and adding paragraphs 

(b)(18) and (19) to read as follows: 

§ 78.1 Purpose and scope. 

(a)(1) This part shall govern appeals of 

any final decision of the Administrator 

under subparts MMM and NNN of part 

62 of this chapter, part 72, 73, 74, 75, 

76, or 77 of this chapter, subparts AA 

through II of part 96 of this chapter or 

State regulations approved under 

§ 51.123(o)(1) or (2) of this chapter, 

subparts AAA through III of part 96 of 

this chapter or State regulations 

approved under § 51.124(o)(1) or (2) of 

this chapter, subparts AAAA through 

IIII of part 96 of this chapter or State 

regulations approved under 

§ 51.123(aa)(1) or (2) of this chapter, part 

97 of this chapter, or subpart RR of part 

98 of this chapter; provided that matters 

listed in § 78.3(d) and preliminary, 

procedural, or intermediate decisions, 

such as draft Acid Rain permits, may 

not be appealed. All references in 

paragraph (b) of this section and in 

§ 78.3 to subparts AA through II of part 

96 of this chapter, subparts AAA 

through III of part 96 of this chapter, 

and subparts AAAA through IIII of part 

96 of this chapter shall be read to 

include the comparable provisions in 

State regulations approved under 

§ 51.123(o)(1) or (2) of this chapter, 

§ 51.124(o)(1) or (2) of this chapter, and 

§ 51.123(aa)(1) or (2) of this chapter, 

respectively. 

* * * * * 

(b) * * * 

(18) Under subpart MMM of part 62 

of this chapter, 

(i) The decision on allocation of CO2

allowances under § 62.16240 of this 

chapter. 

(ii) The decision on allocation of CO2

allowances from set-asides under 

§ 62.16245 of this chapter. 

(iii) The decision on the transfer of 

CO2 allowances under § 62.16330 of this 

chapter. 

(iv) The decision on the deduction of 

CO2 allowances under § 62.16340 of this 

chapter. 

(v) The correction of an error in an 

ATCS account under § 62.16355 of this 

chapter. 

(vi) The adjustment of information in 

a submission and the decision on the 

deduction and transfer of CO2

allowances based on the information as 

adjusted under § 62.16370 of this 

chapter. 

(vii) The finalization of compliance 

period emissions data, including 

retroactive adjustment based on audit. 

(19) Under subpart NNN of part 62 of 

this chapter, 

(i) The decision on emission rate 

credit issuance, adjustment, and 

revocation under § 62.16435. 

(ii) The decision on qualification 

status of eligible resources to receive 

emission rate credits under § 62.16460. 

(iii) The decision on revocation of 

qualification status of an eligible 

resource under § 62.16440. 

(iv) The decision on Adjustments for 

error or misstatement, suspension of 

ERC issuance under § 62.16450. 

(v) The decision on accreditation of 

independent verifiers under § 62.16470. 

(vi) The decision on revocation of 

accreditation status under § 62.16480. 

(vii) The decision on the transfer of 

emission rate credits under § 62.16530 

of this chapter. 

(viii) The decision on the deduction 

of emission rate credits under 

§ 62.16535 of this chapter. 

(ix) The correction of an error in an 

ATCS account under § 62.16550 of this 

chapter. 

(x) The adjustment of information in 

a submission and the decision on the 

deduction and transfer of emission rate 

credits based on the information as 

adjusted under § 62.16565 of this 

chapter. 

(xi) The finalization of compliance 

period emissions data, including 

retroactive adjustment based on audit. 

* * * * * 

[FR Doc. 2015–22848 Filed 10–22–15; 8:45 am] 

BILLING CODE 6560–50–P 

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