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For the reasons stated in the preamble, title 40, chapter 

I, part 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, deletion, 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 will, within 12 

months after the date on which the submission of a plan or plan 

revision is received, approve or disapprove such plan or 

revision, or each portion thereof.

(c) The Administrator must promulgate a federal plan within 

12 months after the date the Administrator:
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(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.

* * * * *
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(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 must 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 paragraph (g) 

of this section, 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;
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(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;
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(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 

requirements to determine the performance of the plan as a 

whole; and

(vi) Demonstration that each emission standard is 

quantifiable, non-duplicative, permanent, verifiable, and 

enforceable.
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(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)(E) through (I) 

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.
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(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 
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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.
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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

Sec.

Introduction

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 mass-based 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?
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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? 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?

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? 
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Definitions

62.16375 What definitions apply to this subpart? 

62.16380 What measurements, abbreviations, and acronyms apply to 

this subpart? 

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. 
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(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 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 
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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.
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(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 
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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 § 

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 
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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 
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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 Mass-based Trading Program; and
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(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 
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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 Mass-based 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 Mass-Based Trading Program, to begin on the 
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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 Mass-Based 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) 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 
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types of eligible renewable energy (RE)) and demand-side energy 

efficiency (EE) projects:

(1) Metered wind power;

(2) Metered solar power; and

(3) Demand-side EE implemented in a low-income community.

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 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:
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(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 set-aside 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 mass-based 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 
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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*(short tons)

Interim Period

P

State

Compliance 

Period 1

2022-2024

Compliance 

Period 2

2025-2027

Compliance 

Period 3

2028-2029

c 

p 

a 

Alabama 66,164,470 60,918,973 58,215,989

Arizona 36,032,671 32,953,521 31,253,744

Arkansas 35,189,232 32,371,942 30,906,226

California 53,500,107 50,080,840 48,736,877

Colorado 35,785,322 32,654,483 30,891,824

Connecticut 7,555,787 7,108,466 6,955,080

Delaware 5,348,363 4,963,102 4,784,280

Florida 119,380,477 110,754,683 106,736,177

Georgia 54,257,931 49,855,082 47,534,817

Idaho 30,408,352 27,615,429 25,981,975

Illinois 1,615,518 1,522,826 1,493,052

Indiana 80,396,108 73,124,936 68,921,937

Iowa 92,010,787 83,700,336 78,901,574
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Kansas 26,763,719 24,295,773 22,848,095

Kentucky 76,757,356 69,698,851 65,566,898

Lands of the 

Fort Mojave Tribe

636,876 600,334 588,596

Lands of the 

Navajo Nation

26,449,393 23,999,556 22,557,749

Lands of the 

Uintah and Ouray 

Reservation

2,758,744 2,503,220 2,352,835

Louisiana 42,035,202 38,461,163 36,496,707

Maine 13,360,735 12,511,985 12,181,628

Maryland 17,447,354 15,842,485 14,902,826

Massachusetts 2,251,173 2,119,865 2,076,179

Michigan 56,854,256 51,893,556 49,106,884

Minnesota 27,303,150 24,868,570 23,476,788

Mississippi 67,312,915 61,158,279 57,570,942

Missouri 28,940,675 26,790,683 25,756,215

Montana 13,776,601 12,500,563 11,749,574

Nebraska 60,975,831 55,749,239 52,856,495

Nevada 25,453,173 23,095,610 21,708,108

New Hampshire 22,246,365 20,192,820 18,987,285

New Jersey 4,461,569 4,162,981 4,037,142

New Mexico 18,241,502 17,107,548 16,681,949
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New York 14,789,981 13,514,670 12,805,266

North 

Carolina

15,076,534 14,072,636 13,652,612

North Dakota 35,493,488 32,932,763 31,741,940

Ohio 88,512,313 80,704,944 76,280,168

Oklahoma 47,577,611 43,665,021 41,577,379

Oregon 9,097,720 8,477,658 8,209,589

Pennsylvania 106,082,757 97,204,723 92,392,088

Rhode Island 3,811,632 3,592,937 3,522,686

South 

Carolina

31,025,518 28,336,836 26,834,962

South Dakota 4,231,184 3,862,401 3,655,422

Tennessee 34,118,301 31,079,178 29,343,221

Texas 221,613,296 203,728,060 194,351,330

Utah 28,479,805 25,981,970 24,572,858

Virginia 31,290,209 28,990,999 27,898,475

Washington 12,395,697 11,441,137 10,963,576

West Virginia 33,505,657 30,571,326 28,917,949

Wisconsin 62,557,024 56,762,771 53,352,666

Wyoming 38,528,498 34,967,826 32,875,725

* The values in this table are annual amounts; the mass goal for eac 

compliance period is the annual value multiplied by the number of years i 

compliance period. Each emission goal includes the renewable energy set-a 
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(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 mass-based emission 

goal.

(c) The renewable energy set-aside for each State covered 

by the federal mass-based 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)

output-based set-asides (the output-based set-asides are zero in the firs 

period).The first compliance period goals also include the early action C 

Incentive Program set-aside. 

Interim Period

Final 

Period

State

Compli

ance Period 

1

2022-

2024

Compli

ance Period 

2

2025-

2027

Compli

ance Period

3

2028-

2029

Final 

compliance 

periods 

2030-

2031
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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

Californ

ia

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

Connecti

cut

377,78

9

355,42

3

347,75

4

347,0

76

Delaware 267,41

8

248,15

5

239,21

4

235,5

91

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 74,64

3
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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 29,42

6

Lands of 

the Navajo 

Nation

1,322,

470

1,199,

978

1,127,

887

1,085

,029

Lands of

the Uintah 

and Ouray 

Reservation

137,93

7

125,16

1

117,64

2

113,1

72

Louisian

a

2,101,

760

1,923,

058

1,824,

835

1,771

,351
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Maine 112,55

9

105,99

3

103,80

9

103,6

97

Maryland 872,36

8

792,12

4

745,14

1

717,3

81

Massachu

setts

668,03

7

625,59

9

609,08

1

605,2

37

Michigan 2,842,

713

2,594,

678

2,455,

344

2,377

,203

Minnesot

a

1,365,

158

1,243,

429

1,173,

839

1,133

,918

Mississi

ppi

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 688,83

0

625,02

8

587,47

9

565,1

55

Nebraska 1,112,

318

1,009,

641

949,36

4

913,6

37

Nevada 753,82

7

703,63

2

682,63

1

676,1

79

New 

Hampshire

223,07

8

208,14

9

201,85

7

199,8

79
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New 

Jersey

912,07

5

855,37

7

834,09

7

829,9

87

New 

Mexico

739,49

9

675,73

4

640,26

3

620,6

30

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 454,88

6

423,88

3

410,47

9

405,9

33

Pennsylv

ania

5,304,

138

4,860,

236

4,619,

604

4,491

,115

Rhode 

Island

190,58

2

179,64

7

176,13

4

176,1

11

South 

Carolina

1,551,

276

1,416,

842

1,341,

748

1,299

,948
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(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 

South 

Dakota

211,55

9

193,12

0

182,77

1

176,9

74

Tennesse

e

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

Washingt

on

619,78

5

572,05

7

548,17

9

536,9

59

West 

Virginia

3,127,

851

2,838,

139

2,667,

633

2,566

,267

Wisconsi

n

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
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(d). The output-based set-asides are specified in Table 3 of

this subpart. 

Table 3 to Subpart MMM of Part 62--. Statewide Output-based Setaside (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
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Oregon 1,291,027

Pennsylvania 4,392,931

Rhode Island 778,307

South Carolina 1,029,366

South Dakota 130,831

Tennessee 632,949

Texas 15,990,657

Utah 825,586

Virginia 3,011,811

Washington 1,383,060

West Virginia 0

Wisconsin 1,181,175

Wyoming 45,114

(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
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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

(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 
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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 
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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 set-aside 

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 
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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 set-aside 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 
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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:
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(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 a state allowance 
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Page 40 of 304

distribution methodology provides should be allocated only to 

recipients that are 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 already-recorded 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.
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(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 set-aside 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 
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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 set-aside 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 setaside, 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.
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(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 set-aside allowances may be issued only 

for the difference in generation between the uprated nameplate 

capacity and its nameplate capacity prior to the uprate. Setaside allowances must not be issued for generation for an uprate 

that followed a derate that occurred on after January 1, 2013. A 

resource that is relicensed or receives a license extension is 

considered existing capacity and is not an eligible resources, 

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 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 set-aside has been designated.
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(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 setaside 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, e-mail 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 
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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 EIA860 (if applicable). 

(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.
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(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 EPAapproved 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:
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(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 Set-Aside Allowances.

The Administrator will enter the projected generation from each 
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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 setaside 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 set-aside 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.
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(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 output-based 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 outputbased set-aside allowances, affected EGUs must meet the 

following eligibility requirements: 
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(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 set-aside 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 pro-rata 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, 
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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 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 set-aside. 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?
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(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, and 

any other requirements may be cause for the Administrator to 

revoke the eligibility of an eligible resource to be issued setaside 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 
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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 set-aside 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 
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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 setaside 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)(i) through (iii) of this 

section.

(i) Freeze the general account of the authorized account 

representative for an eligible resource, preventing any 

transfers of allowances out of the account.

(ii) Revoke or deduct allowances held in the general 

account of the authorized account representative for an eligible 
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resource, in a number equal to the number of allowances issued 

for the ineligible eligible resource.

(iii) 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)(i) through 

(iii) of this section.

(i) 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.

(ii) In the case of repeated error or misstatements in 

submitted M&V reports.

(iii) In the case of an intentional misrepresentation in a 

submitted M&V report.
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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.

(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.
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(i) The generation data is 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 is 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 was 

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 and 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;
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(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 is 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, the data may be self-reported and reported no less 

than annually.
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(v) The generation data serves 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. 
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(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 
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must be clearly delineated, or if the generating unit does not 

generate enough electricity to enable monthly reporting, the 

data may be reported no less than annually.

(v) The generation data are self-reported to 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 setaside 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:
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(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 demonstrate 

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 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
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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 

site-level electricity savings measured at the end use meter or 

the statewide annual average transmission and distribution loss 

rate (expressed as a percentage) from the most recent year that 

is published in the US EIA State Electricity Profile expressed 

as a percentage. No other transmission and distribution loss 
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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 expost 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 
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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 project covered in the EM&V plan, based on:
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(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 direct install 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 best-practice protocols and 

guidelines. Examples of such protocols and guidelines provided 

in EM&V guidance that may be issued by the Administrator will be 

acceptable.
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(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 
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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 
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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. 
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(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 energy-efficient 

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.
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(D) The EE savings verification approaches for ensuring 

that EE measures have been properly installed, is operating as 

intended, and therefore has 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 best-practice approaches, such as physical 

inspections at a customer 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 
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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 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 
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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 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:
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(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
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(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:
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(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.”

(ii) [Reserved]
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(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 
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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 
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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 § 62.16265.

(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. 
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(1) Independent verifiers must have the skills, experience, 

resources (personnel and otherwise) to provide verification 

reports, including the following:

(A) 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;

(B) 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;

(C) Knowledge of the requirements of the Administrator’s CO2

Mass-based Trading Program regulations and related guidance;

(D) 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

(E) 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 
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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 
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part 32 of this chapter, or the Debarment, Suspension and 

Ineligibility provisions of the Federal Acquisition Regulations, 

48 CFR part 9, subpart 9.4, of this chapter.

(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 possess 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 section 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?
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(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, set-aside 
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allowance issuance, or the number of set-aside allowances 

issued); 

(5) Accredited independent verifiers must not own, buy, 

sell, or hold set-aside 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 and disclosed 

to the Administrator any potential COI related to an eligible 

resource.
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(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).
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(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 set-aside 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.
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(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.

DESIGNATED REPRESENTATIVES

§ 62.16290 How are designated representatives and alternate 

designated representatives authorized? 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 
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matters pertaining to the CO2 Mass-based 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;
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(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 
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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 

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 
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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 
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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 number 

(if any)), the date on which the affected EGU was purchased or 
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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 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, 
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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 
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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 distributed in 

accordance with the contract.”

(5) The signature of the designated representative and any 

alternate designated representative and the dates signed.
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(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, 
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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.
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(1) The name, address, e-mail address, telephone number, 

and facsimile transmission number (if any) of such designated 

representative or alternate designated representative.

(2) The name, address, e-mail 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 e-mail account and to notify the Administrator 
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immediately of any change in my e-mail 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 
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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.
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(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 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, e-mail 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 
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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 
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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 
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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.
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(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 
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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 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 
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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 
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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, e-mail address, telephone number, 

and facsimile transmission number (if any) of such authorized 

account representative or alternate authorized account 

representative;

(B) The name, address, e-mail 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 
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(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 e-mail account and to 

notify the Administrator immediately of any change in my e-mail 

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 
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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 Allowance 

Tracking and Compliance System 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 
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account will be closed after 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 
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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 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

Allowance Tracking and Compliance System 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 Allowance Tracking and 

Compliance System 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.
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(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 setaside to the eligible EGUs at the facility in accordance with § 

62.16245(b) or with a state allowance-distribution 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 must be 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
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(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 
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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 non-recordation.

§ 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 
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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 
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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.

(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? 
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(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 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. 
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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 non-combustion 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 
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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 
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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 uses, 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, 
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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 
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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 section over the entire compliance 

period.

(vi) The owner or operator of an affected EGU may determine 

site-specific 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 
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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 
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output value reported under part 75 of this chapter to MWh, 

multiply by the corresponding EGU or stack operating time.

Pnet = 

(Pe)ST + (Pe)CT + (Pe)IE − (Pe)A

TDF

+ [ (Pt)PS + (Pt)HR + (Pt)IE ]

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 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 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) from any integrated equipment is 

used for applications that do not generate 

additional steam, electricity, produce mechanical 
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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:

(Pt)PS = Qm × H

CF

Where:

(Pt)ps = Useful thermal output of steam (measured relative to 

SATP conditions, 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 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 x 109 J/MWh or 3.413 x 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 
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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.

(b) [Reserved]

§ 62.16350 May I bank CO2 annual allowances for future use or 

transfer?
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(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 Allowance 

Tracking and Compliance System 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 
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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 or a compliance 

period, then you must include the CO2 emission standard with 

which your affected EGU must comply, the affected EGUs 

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 
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must include in their report the eligible resource 

identification information sufficient to demonstrates 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).

(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 
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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 onsite; 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, 
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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 Massbased 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 set-aside 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 
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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.

§ 62.16370 What actions may the Administrator take on 

submissions?

(a) The Administrator may review and conduct independent 

audits concerning any submission under the CO2 Mass-based 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 multi-state 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.
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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/MWhr or, if in lb/mmBtu, converted to lb/MWhr by multiplying 

it by the affected EGU's heat rate in mmBtu/MWhr) that is 

applicable to the affected EGU and covers the longest averaging 

period not exceeding 1 year.
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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 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 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 Massbased Trading Program facility and each affected EGU at the 
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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 
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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 
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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 setaside, 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.
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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 MassBased 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 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.
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CO2 emission goal means a statewide rate-based CO2 emission 

goal or mass-based 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 

steam-generating unit or stationary combustion turbine to 

simultaneously produce both electric (or mechanical) and useful 

thermal output from the same primary energy facility.
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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 marketaverage or pre-existing 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 2 or more units are exhausted.

Compliance account means an Allowance Tracking and 

Compliance System 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 multi-year 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:
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(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) or 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.xx30 through 62.xx35. 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; 
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(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 demandside EE measure that: (a) has been developed from data sources 

(such as prior metering studies) and analytical methods widely 

considered acceptable for the measure, and (b) is applicable to 
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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 

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 units 

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 
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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.

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 privately-funded 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 
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as part of an EE program or as an independent privately-funded 

action.

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.

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 EPAadministered 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 

affected EGU is required to measure, record, and report such air 
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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. 

Energy service company means a private enterprises engaged 

in delivering electricity savings directly for an end-use 

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, 
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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 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).

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. 

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.
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Gaseous fuel the definition as defined in subpart TTTT of 

part 60 of this chapter.

General account means an Allowance Tracking and Compliance 

System account established under this subpart that is not a 

compliance account.

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. 

Generation period means the compliance period from which 

the Administrator uses operations data of affected EGUs to 

calculate allowances from the output-based allocation set-aside 

for the following compliance period. 

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 the fuel feed rate (in lb of fuel/time), as 
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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-
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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 (15o 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 
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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) as 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) as of such completion as specified by the 

person conducting the physical change.

Natural gas the definition as defined in subpart TTTT of 

part 60 of this chapter.
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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; 
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(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 
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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, 

an affected EGU that is unavailable for service and for which 

the affected EGU's owners and operators (1) have taken on as 

enforceable obligations in the operating permit that covers the 

affected EGU the conditions of 62.16215, or (2) 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.

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 
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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 Allowance Tracking and Compliance 

System 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).
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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, fossilfuel-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.

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.

Standard ambient temperature and pressure (SATP) conditions

means 298.15 Kelvin (25o C, 77 oF)) 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.
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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 subcomponents 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.
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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.

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.
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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.
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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 ongoing 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 

quality-assured 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.
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§ 62.16380 Measurements, abbreviations, and acronyms. 

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
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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
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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? 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 
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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 

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 40 CFR 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 40 CFR 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, 40 CFR 51.166(b)(48) 

of this chapter. 

(2) For the purposes of 40 CFR 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 40 CFR 52.21(b)(49) of this chapter. 

(3) For the purposes of 40 CFR 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 
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that otherwise is "subject to regulation" as defined in 40 CFR 

70.2 of this chapter. 

(4) For the purposes of 40 CFR 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 40 CFR 

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)(1) Any affected EGU that is permanently retired as 

defined in § 62.16570 is exempt from §§ 62.16420(c)(1) [CO2
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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.
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(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 
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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: 

CO2emission rate = ∑ MCO2

∑ MWhop + ∑ MWh ERC

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).

(2) An emission rate credit (ERC) qualifies for the 

compliance demonstration specified in paragraph (c)(1) of this 

section if it: 

(i) Has a unique serial number;
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(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 Allowance Tracking and Compliance System; 

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 Allowance Tracking and Compliance 

System.

(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:
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(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, 
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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 (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) Allowance Tracking and Compliance System (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 
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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.
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(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 Rate-Based 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 Rate-Based 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 
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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) 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 emission rate credits (ERCs) for generation and 

savings achieved in 2020 and/or 2021 that result from the 

following types of eligible renewable energy (RE) and demandside energy efficiency (EE) projects:

(1) Metered wind power;

(2) Metered solar power; and

(3) Demand-side EE implemented in a low-income community.

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 
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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 

rate-based 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 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 two early action ERCs under paragraph 
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(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:

ERCs = (EGU emission standard−EGU emission rate)

EGU emission standard ∗ EGU generation

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.
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(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 Rate

= 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:

GS-ERC Emission Factor = 1 − EGU emission rate

Steam Turbine Emission Standard

Where:

GS-ERC Emission 

Factor

= Factor to be used in the equation in 

paragraph (c)(1) of this section for GSERC 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.
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§ 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 after January 1, 2013. A resource that is relicensed 

or receives a license extension is considered existing capacity 

and is not an eligible resources, 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 difference in 
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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 rate-based emission standards pursuant to this 

regulation, unless the resource is located in a State with massbased 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 
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(vi) A demand-side EE or demand-side 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 
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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, and 

any other requirements 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? 
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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 ERC resource, including the authorized account 

representative’s name, address, e-mail 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 
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customer load, customer-sited distributed generator) (if 

applicable); facility and generating unit IDs (EIA ORIS Code, 

Facility Registration System (FRS) Code, if applicable); for 

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 energy-saving project, 
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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 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), enduse(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 
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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 enduse(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 
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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 EPAapproved 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 
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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 § 

62.16445(a), 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 
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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?
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(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 result in prohibition of the authorized account 

representative for the eligible resource from further 
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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.
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(3) In the event that the general account of the ERC 

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 
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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 is 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 
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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 is 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 was 

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 and 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 
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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 is 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, the 

data may be self-reported and reported no less than annually.

(v) The generation data serves 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 
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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 onsite 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) 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; 
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(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, the 

data may be reported no less than annually.

(iv) The generation data are self-reported to distribution 

utility through an electronic internet-based portal with 

software that reports total and hourly generation.
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(v) The generation data serves 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.

(vi) 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 is measured with the relevant 

method approved by the EPA in connection with the specific State 
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plan pursuant to which that EM&V plan is submitted demonstrate 

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 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 40 CFR 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 
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emission unit CO2 emission monitoring and reporting methodology 

in 40 CFR 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.
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(i) All electricity savings must be quantified on an expost 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.
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(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 project 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 direct install 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
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(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 best-practice 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 
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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 
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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 
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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. 
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(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 energy-efficient 

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, is operating as 

intended, and therefore has 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 best-practice approaches, such as physical 

inspections at a customer premises, phone and mail surveys, and 

reviews of sales receipts and other documentation. If such 
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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 
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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 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]
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§ 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 
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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 
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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.
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(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 

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).
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(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) That 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 ERC 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 
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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 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 ERC 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 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 
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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, 

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 
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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, 
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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, 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, of this chapter.

(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 possess a 

financial strength rating in the top four categories from either 

Standard & Poor’s or Moody’s, specifically, AAA, AA, A or BBB 
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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 section 62.16475 when providing verification 

services for an authorized account representative; and 

(2) The instances specified in section 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 
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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 
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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 
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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 
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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? 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 
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designated representative, with regard to all matters under the 

CO2 Rate-based 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 Ratebased 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 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.
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(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 or any 

alternate designated representative.

§ 62.16490 What responsibilities do designated representatives 

and alternate designated representatives hold?
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(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.
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§ 62.16495 What are the processes for changing designated 

representative, alternate designated representative, owners and 

operators?

(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.
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(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.
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(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 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 

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) 
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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, 

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, e-mail 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:
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(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 
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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 
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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 
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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, e-mail address, telephone number, 

and facsimile transmission number (if any) of such designated 

representative or alternate designated representative;

(2) The name, address, e-mail 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
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(ii) “Until this notice of delegation is superseded by 

another notice of delegation under § 62.16510(d), I agree to 

maintain an e-mail account and to notify the Administrator 

immediately of any change in my e-mail 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 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 
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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 
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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.
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(ii) A complete application for a general account must 

include the following elements in a format prescribed by the 

Administrator:

(A) Name, mailing address, e-mail 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 
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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; 
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(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. 
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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 
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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.
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(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 
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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 
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a notice of delegation, in a format prescribed by the 

Administrator, that includes the following elements:

(A) The name, address, e-mail address, telephone number, 

and facsimile transmission number (if any) of such authorized 

account representative or alternate authorized account 

representative;

(B) The name, address, e-mail 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
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(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 e-mail account and to 

notify the Administrator immediately of any change in my e-mail 

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.

(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.
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(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 Allowance Tracking and Compliance 

System 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 after 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 
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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 beings 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 section § 62.16435(a)(4);
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(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 § 62.16515(g). This information 

will be accessible via an electronic, internet-based 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 
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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 § 62.16515(g);

(2) Public Reports. By the public, reports that include: 

all of the information listed in § 62.16515(g); a list of all 

registered account holders in the ERC tracking system, including 

compliance accounts and general accounts; a list of all ERC 

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 § 62.16515(g) 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 
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system may provide for transfers of ERCs to/from another ERC 

tracking system approved in connection with s 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 must be 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
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(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, 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.
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(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 non-recordation.

§ 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 
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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 
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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) 
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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 
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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

(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 
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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 uses, 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 
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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 

site-specific 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 
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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, 
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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.

Pnet = 

(Pe)ST + (Pe)CT + (Pe)IE − (Pe)A

TDF

+ [ (Pt)PS + (Pt)HR + (Pt)IE ]

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.
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(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 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)(5)(i)(B) of this section in MWh.

(Pt)HR = Non steam useful thermal output (measured 

relative to SATP conditions, 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) 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:

(Pt)PS = Qm × H

CF
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Where:

(Pt)ps = Useful thermal output of steam (measured relative to 

SATP conditions, 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 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 x 109 J/MWh or 3.413 x 106 

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), 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 
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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), 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]
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§ 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 Allowance 

Tracking and Compliance System 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?

(a) You must prepare and submit reports according to 

paragraphs (a) through (g) 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 percentage of valid operating hours in each quarter 

described 62.16540(a)(2) (i.e., the total number of valid 
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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 or 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 all if an affected EGU is 

complying with an emission standard by using ERCs the designated 
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representative must include in their 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).

(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
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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 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 onsite; or
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(2) Transfer the captured CO2 to an affected 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.

(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 (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. 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 
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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 Rate-based 

Trading Program.

(iv) Data that is required to be recorded by 40 CFR 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 
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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 Rate-based 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 multi-state SO2 and NOX air 

pollution control and emission reduction program established by 
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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/MWhr or, if in lb/mmBtu, converted to lb/MWhr by multiplying 

it by the affected EGU's heat rate in mmBtu/MWhr) that is 

applicable to the affected EGU and covers the longest averaging 

period not exceeding 1 year.

Allowance Tracking and Compliance System 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.

Allowance system means a control program under which the 

owner or operator of each affected EGU is required to hold an 
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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.

Alternate designated representative means, for a CO2 Ratebased 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.
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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 Rate-based 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. 
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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 setaside, 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 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.
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Combined heat and power unit or CHP unit, (also known as

“cogeneration”) means an electric generating unit that use a 

steam-generating 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 marketaverage or pre-existing 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 2 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.
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Compliance period means the multi-year 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;

(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) or 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:
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(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.
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Deemed savings means estimates of average annual 

electricity savings for a single unit of an installed demandside EE measure that (a) has been developed from data sources 

(such as prior metering studies) and analytical methods widely 

considered acceptable for the measure and (b) 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 

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 units 

capacity for planning purposes. 

Designated representative means, for a CO2 Rate-based 

Trading affected EGU and each affected EGU at the affected EGU, 
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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 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-
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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 

affected EGU 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 
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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 privately-funded 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 privately-funded 

action.

ERC held or hold ERCs means the ERCs treated as included in 

an Allowance Tracking and Compliance System 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, 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.
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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, 
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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 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).

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. 

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.
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Gaseous fuel means the definition as defined in subpart 

TTTT of part 60 of this chapter.

General account means an Allowance Tracking and Compliance 

System 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 
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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 solidderived 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. 
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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 (15o 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 
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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) as 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) as 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 
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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 
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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 a 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 
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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, 

an affected EGU that is unavailable for service and for which 

the affected EGU's owners and operators (1) have taken on as 

enforceable obligations in the operating permit that covers the 

affected EGU the conditions of 62.16415, or (2) 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 
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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 Allowance Tracking and Compliance System 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. 
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Solid waste incineration unit means a stationary, fossilfuel-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.

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.

Standard ambient temperature and pressure (SATP) conditions

means 298.15 Kelvin (25o C, 77 oF) 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 
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control technology, and any ancillary components and subcomponents 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;
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(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.

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 
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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 ongoing quality assurance, the daily, quarterly, and 
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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 

quality-assured 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 Measurements, abbreviations, and acronyms. 

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
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COI—conflict of interest

CVR—conservative 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

T&D—transmission and distribution

O2—oxygen

PSD-prevention of significant deterioration

yr—year
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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 et seq.

7. Section 78.1 is amended by revising paragraph (a)(1) and 

adding paragraphs (b)(18) and (b)(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 
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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.
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(ii)The decision on allocation of CO2 allowances from setasides 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 Allowance Tracking and 

Compliance System 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 reduction 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.
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(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 reduction 

credits under § 62.16530 of this chapter.

(viii) The decision on the deduction of emission reduction 

credits under § 62.1616535 of this chapter.

(ix) The correction of an error in an Allowance Tracking 

and Compliance System 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 reduction 

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.

* * * * *