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 p art 60 continues to read as follows: **Authority:** 42 U.S.C. 7401 et seq .
2. Section 60.27 is amended as follow by :

a. by r evis ing R evis ing paragraphs (b) , (c) introductory text, and (c)(1 ), (c)(3), (d), and (e) (1) ; ) ; b. by Removing and r eserv ing paragraph (c)(2); and

c. by add ing c. R evis ing paragraphs (c)(3), (d), and (e)(1); and d

. A dd ing paragraph s (g ) , (h), (i), (j), and ) 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 twelve 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. Style Definition: Normal (Web): Font: Space Before: 0 pt, After: 8 pt, Line spacing: Multiple 1.08 li

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Formatted: Indent: First line: 0"(c) The Administrator shall must promulgate a federal plan within twelve 12 months after the date the Administrator : (1) finds F inds t he s tate S tate fail ed to submit a complete plan or complete plan revision within the time prescribed; or (2) (reserved)

.

* * * * * ( 3 ) disapproves D isapproves the s tate S tate 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 determines to be approvable. approve s . After the promulgation of a federal plan,
t he Administrator may approve a state S tate 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 corres ponding emission guideline(s) specified in the final guideline document published under § 60.22(a) and willrequire final compliance with such standards as expeditiously as practicable but no later than the times specified in the guideline document.

* * * * * (g) Completeness Criteria c riteria

. (1) General

. Within 60 days of the Administrator's receipt of a s tate submission, but no later than six 6 months after the date, if any, by which a state S tate is required to submit the plan or revision, the Administrator shall must determine whether the minimum criteria for completeness have been met. Any plan or plan revision that a state S tate submits to the EPA, and that has not been determined by the EPA by t he date six 6 months after receipt of the submission to have failed to meet the minimum criteria, shall on that date be deemed by operation of law to meet such minimum criteria. Where the Administrator determines that a plan submission does not meet the minimum criteria of this paragraph (g) of this section , the state shall S tate will be treated as not having made the submission. (2) Administrative criteria

. In order to be complete, a
state S tate plan must contain each of the following administrative criteria : ( A i ) A formal letter of submittal from the Governor or her designee requesting EPA approval of the plan or revision thereof;( B ii ) Evidence that the state S tate has adopted the plan in the s tate code or body of regulations. That evidence shall 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; ( C iii ) Evidence that the state S tate has the necessary legal authority under s tate law to adopt and implement the plan; ( D iv ) A copy of the actual regulation, or document submitted for approval and incorporation by reference into the plan. The submittal shall must be a copy of the official s tate regulation or document signed, stamped and dated by the appropriate s tate official indicating that it is fully enforceable by the state S tate . The effective date of the regulation or document shall must , whenever possible, be indicated in the document i tself. The state’s S tate’s electronic
copy must be an exact duplicate of the hard copy. For revisions to the approved plan, the submittal shall must indicate the changes made (for example, by redline/strikethrough) to the approved plan; ( E v ) Evidence that the state S tate followed all of the procedural requirements of the s tate's laws and constitution in conducting and completing the adoption and issuance of the plan;( F vi ) Evidence that public notice was given of the proposed change with proc edures consistent with the requirements of 40
CFR § 60.23, including the date of publication of such notice; ( G vii ) Certification that public hearing(s) were held in accordance with the information provided in the public notice and the state's S tate's laws and constitution, if applicable and consistent with the public hearing requirements in 40 CFR § 60.23; and ( H viii ) Compilation of public comments and the
state's S tate's response thereto

. ; and ( I 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 S tate plan must contain each of the following technical criteria: ( A i ) Description of the plan approach and geographic scope; ( B 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; ( C iii ) Identification of complianc e schedules and/or increments of progress; Formatted: Underline, English (United States)

Formatted: English (United States)( D iv ) Demonstration that the state S tate plan submittal is projected to achieve emissions performance under the applicable emission guidelines; ( E v ) Documentation of s tate recordkeeping and reporting requirements to determine the performance of the plan as a whole; and ( F vi ) Demonstration that each emission standard is quantifiable, non

- duplicative, permanent, verifiable, and enforceable. (4) Parallel Processing p rocessing

. A State may submit a
state S tate plan prior to actual adoption by the S tate in order to expedite review and provide an opportunity for the S tate to consider EPA comments prior to submission of a final plan for final review and action. Under these circumstances, the following exceptions t o the criteria in this paragraph apply to plans submitted explicitly for parallel processing: (A) the ( i ) T he letter required by paragraph (g)(2)( A) shall i ) of this section must request that EPA propose approval of the proposed plan by parallel processing; (B) in ( ii ) I n lieu of paragraph (g)(2)( B) ii ) of this section the
State shall must submit a schedule for final adoption or issuance of the plan; (C) in ( iii ) I n lieu of paragraph (g)(2)( D) iv ) of this section the plan shall must include a copy of the proposed/draft regulation Formatted: Underlineor document, including indication of the proposed changes to be made to the existing approved plan, where applicable; and (D) the ( iv ) T he requirements of paragraphs (g)(2)(E) through (I) shall of this section do not apply to plans submitted for parallel processing. The exceptions granted in the preceding
sentence shall apply only to EPA’s determination of proposed action and all requirements of paragraph (g)(2) shall of this section must be met prior to publication of EPA’s final determination of plan approvability. (h) Full and Partial Approval p artial a pproval and Disapproval d isapproval . 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 conjunc tion with a federal plan, where in combination, the federal and state S tate plans constitute a complete and approvable plan meeting all of the requirements of this subpart and the applicable emissions guidelines. (i ) Conditional Approval a pproval . 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 Formatted: Indent: First line: 0.5"

Formatted: Underlineappropriate state S tate plans , or otherwise commit to ma king changes in the state’s S tate’s plan necessary to meet the requirements of the applicable emission guidelines. Any such conditional approval shall automatically convert convert s 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. p lan r evisions

. 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 shall must require the state S tate to revise the plan as necessary to correct such inadequacies. The Administrator shall 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 shall 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 subm itted the plan for which such finding was made, except that the Administrator may adjust any dates applicable under such requirements as appropriate. Formatted: Underline( k ) Error Corrections c orrections . 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 promulga tion 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 p art 6 2 continues to read as follows: **Authority:** 42 U.S.C. 7401 et seq . 4. Add subpart MMM to read as follows: **Subpart MMM: Greenhouse Gas Emissions Mass -**  **based Model Trading Rule for Electric**  **Utility Generating Units that Commenced Construction on or Before January 8, 2014** 
Sec.
**In troduction**  62.16205 What is the purpose of this subpart? **Applicability of this Subpart** 62.16210 Am I subject to this subpart? 62.16215 What rules requirements apply to affected EGUs that retire? Formatted: Underline

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Formatted: Font: Not Italic, Underline**General Requirements** 62.16220 What are requirements must I comply with? 62.16225 How should I compute time under the CO 2 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 ? How much is reserved for set

- asides? , renewable energy s et

- asides, output

- based set

- asides , and Clean Energy Incentive Program early action set

- asides? 62.16240 When are allowances allocated? 62.16245 How are set

- aside allowances allocated? 62.16250 What is the process for revocation of qualification status of an eligible resource? 62.16255 What is the process for error adjustments or misstatement, and suspension of allowance issuance? **Evaluation Measurement and Verification Plans, Monitoring and Verification Reports, and**  **Verification** 62.16260 What are the requirements for evaluation , measurement and verification plans for eligible resources? 62.16265 What are the requirements for monitoring and verification reports for eligible resources? 62.16270 What are the requirements for verification reports? 62.16275 What is the accreditation procedure for independent verifiers? 62.16280 What are the procedures of accredited independent verifiers must follow to avoid conflict of interest? 62.16285 What is the process for the revocation of accreditation statu s 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? Formatted: Line spacing: single62.16300 What are the processes for changing designated representatives, alternate designated representatives, owners and operators, and affected E GUs 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 CO 2 allowances be recorded in compliance accounts? 62.16330 How must transfers of CO 2 allowances be submitted? 62.16335 When will CO 2 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 CO 2 annual allowances for future use or transfer? 62.16355 How does the Administrator process account errors? 62.16360 What are my reporting, notification and submission requirements? 62.16365 What are my recordkeeping requirements? 62.16370 What actions may the Administrator take on submissions? **Definitions** 62.16375 What definitions apply to this subpart? 62.16380 What measurements, abbreviations, and acronyms apply to this subpart?

**Introduction §**  **62.16205 What is the purpose of this subpart?** ( a) This subpart sets forth the general, designated representative, allowance, and monitoring provisions requirements Formatted: Font: Courier New, 12 pt

Formatted: Line spacing: singlefor the Clean Power Plan (CPP) CO 2 Mass

- based Trading Program, under section 111 of the Clean Air Act and §XX.XX subpart UUUU of
p art 60 of this chapter, as a means of meeting emission guidelines limiting greenhouse gas emissions from an affected steam generating unit, integrated gasificatio n 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 (CO 2 ). ( c ) PSD and t itle V t h resholds for g reenhouse g ases. (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 conside red 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 cha pter. (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 otherw ise 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 promul gated 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 faci lities, 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 S tate that has incorporated by reference this subpart as a state S tate plan, or portion of a state S tate plan, that has been approved by the Administrator and is effective under subpart UUUU of Part p art 60 of this chapter, or if this subpart is promulgated and effective as a federal plan in your
state S tate under Part p art 62 o f this chapter. (b) An affected EGU is any steam generating unit, Integrated Gasification Combined Cycle ( IGCC ), , or stationary Formatted: No underline Formatted: No underline Formatted: No underlinecombustion turbine that meets the applicability requirements in
§ § § 60.5840(b) and § 60.5845 of this chapter. **§62.1621 5**  **What are the**  **requirements for retired**  **apply to affected** 
**EGUs ?**  **that retire? ?**  (a )( ) Exemption

. ( 1) Any affected EGU that is permanently retired pursuant to an enforceable title V operating permit condition shall be as defined in § 62.16375 is exempt from
§ § § 62.16220 (c)(1 )[ ) [ CO 2 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 shall 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 shall must submit a statemen t to the Administrator. The statement shall 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 shall must not emit any CO 2 , starting on the date that the exemption takes effect. Formatted: No underline Formatted: No underline

Formatted: Underline(2) For a period of five 5 years from the date the records are created, the owners and operators of an affected EGU exempt under paragraph (a) of this section shall must retain, at the facility that includes the unit, records demonstrating that the affected EGU is permanently retired . The five 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 shall must comply with the requirements of the CO 2 Mass

- based Trading Program concerning all accruing during a ny compliance periods for which the exemption is not in effect, even if such requirements arise, or

m ust 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 shall comply with the requirement to must have a designated representative, and may have an alternate designated representative, in accordance with §§62.16290 through 62.16300. (b) Emissions monitoring, reporting, and recordkeeping requirements. (1) The owners and operators, and the designated Formatted: Font: Courier New
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Formatted: Font: Not Italic, Underlinerepresentative, of each facility and each affected EGU at the facility shall 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 shall must be used to calculate allocations of CO 2 allowances under §§62.16240(a )(2) ) and (b) and to determine compliance with the CO 2 emissi on 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 shall must be the mass emissi ons amount for the monitoring location determined in accordance with §§62.16345 and rounded to the nearest ton

. (c) CO 2 emission standard requirements. (1) CO 2 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 shall must hold, in the facility's compliance account, CO 2 allowances ava ilable for deduction for such compliance period under §62.16340(a) in an amount not less than the tons of total CO 2 emissions for such compliance period from all affected EGUs at the facility. Formatted: Font: Not Italic, Underline
Formatted: Underline(ii) If total CO 2 emissions during a compliance period in a giv en year from the affected EGUs at a facility are in excess of the CO 2 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 shall must hold the CO 2 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 CAA Clean Air Act , and the United States, states S tates , 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 shall 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 shall will constitute a separate violation of this subpart and the Clean Air Act

. (2) Compliance periods. (i) An affected EGU shall will be subject to the requirements under paragraph (c)(1) of this section for the Formatted: Font: Not Italic, Underlinecompliance period starting on January 1, 2022 and for each compliance period thereafter. (ii) [Reserved] (3) Vintage of allowances held for compliance . (i) A CO 2 allowance held for compliance with the requirements under paragraph (c)(1)(i) of this section for a compliance period must be a CO 2 allowance that was allocated for a year in such

com pliance period or for a year in a prior compliance period. (ii) A CO 2 allowance held for compliance with the requirements under paragraphs paragraph (c)(1)(ii)(A) of this section for a compliance period must be a CO 2 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 CO 2 allowance shall must be held in, deducted from, or transferred into, out of, or between ATCS accounts in accordance with this subpart. (5) Limited authorization . A CO 2 allowance is a limited authorization to emit one ton of CO 2 during the compliance period in one year. Such a uthorization is limited in its use and duration as follows: (i) Such authorization shall must only be used in accordance with the CO 2 Mass

- based Trading Program; and Formatted: Underline

Formatted: Underline

Formatted: Underline(ii) Notwithstanding any other provision of this subpart, the Administrator has the authori ty 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 CO 2 allowance does not constitute a property right. (d) Title V permit requirements

. (1) Unless otherwise specified in this paragraph, all requirements of this subpart shall be 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 c hanged 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 shall will be required for any allocation, holding, deduction, or transfer of CO 2 allowances Formatted: Underline

Formatted: Font: Not Italic, Underline Formatted: Font: Not Italicin accordance with this subpart, provided that the requirements applicable to such allocations, holdings, deductions, or transfers of CO 2 allowances are already in corporated in such permit. (e) Liability. (1) Any provision of the CO 2 Mass

- based Trading Program that applies to an affected EGU at a facility or the designated representative of affected EGUs at a facility shall will also apply to the owners and operators of such facility and of the affected EGUs at the facility. (2) Any provision of the CO 2 Mass

- based Trading Program that applies to an affected EGU or the designated representative of an affected EGU shall will also ap ply to the owners and operators of such affected EGU. (f) Effect on other authorities. No provision of the CO 2 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 s tate implementation plan, a federally enforceable permit,

or any other requirement of the Clean Air Act

. **§ §**  **§ 62.16225 How should I compute time**  **under the CO 2**  **Mass -**  **based Trading Program?**  Formatted: Font: Not Italic, Underline

Formatted: Font: Not Italic, Underline(a) Unless otherwise stated, any time period scheduled, under the CO 2 Mass

- Based Trading Program, to begin on the occurrence of an act or event shall will begin on the day the act
or event occurs. (b) Unless other wise stated, any time period scheduled, under the CO 2 Mass

- Based Trading Program, to begin before the occurrence of an act or event shall will be computed so that the period ends the day before the act or event occurs. (c) Unless otherwise stated, if the fi nal day of any time period, under the CO 2 Mass

- Based Trading Program, is not a business day, then the time period shall 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 CO 2 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 savingsachieved in 2020 and 2021 that result from the following types of renewable energy and demand

- side energy efficiency ( EE ) projects implement ed in or benefitting the state following September 6, 2018: (1) Metered wind power; (2) Metered solar power; and (3) Demand

- side EE implemented in a low

- income communit y . (b) Early action allowances will be distributed pursuant to a process to be prescribe d 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 mat ch 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 CO 2 emissions

. (d) The awards, including the matching award, will be executed as follows: (1) For RE projects that generate metered MWh from wind or solar resources: for every two MWh generated, the project will receive a number of early action allowances the Administrator determines to be equivalent to one MWh from the set

- aside underparagraph (b) of this section and a number of matching allowances the Adm inistrator 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,**  **and output**  **- based se**  **t -**  **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
CO 2 allowances for the interim three 3

- and two 2

- year compliance periods in 2022 through 2029, and the final two 2

- year compliance periods in 2030 and thereafter are as follows: specified in Table 1 of this subpart.**Table**

**___ 1 to Subpart MMM of Part 62**  **-- Statewide Mass**  **- based**  **Emission Goals***

**(short tons) Interim Period**  **Final Period** 

**State Compliance**  **Period 1 2022**  **- 2024**  **Compliance Period 2**  **2025 -**  **2027 Compliance**  **Period 3 2028**  **- 2029**  **Final compliance** 

**periods 2030**  **- 2031**  **and thereafter**  Alabama 66,164,470 60,918,973 58,215,989 56,880,474 Arizona 36,032,671 32,953,521 31,253,744 30,322,632 Arkansas 35,189,232 32,371,942 30,906,226 30,170,750 California 53,500,107 50,080,840 48,736,877 48,410,120 Colorado 35,785,322 32,654,483 30,891,824 29,900,397 Connecticut 7,555,787 7,108,466 6,955,080 6,941,523 Delaware 5,348,363 4,963,102 4,784,280 4,711,825 Florida 119,380,477 110,754,683 106,736,177 105,094,704 Georgia 54,257,931 49,855,082 47,534,817 46,346,846 Idaho 30,408,352 27,615,429 25,981,975 25,018,136 Illinois 1,615,518 1,522,826 1,493,052 1,492,856 Indiana 80,396,108 73,124,936 68,921,937 66,477,157 Iowa 92,010,787 83,700,336 78,901,574 76,113,835 Kansas 26,763,719 24,295,773 22,848,095 21,990,826 Kentucky 76,757,356 69,698,851 65,566,898 63,126,121 Lands of the Fort Mojave Tribe 636,876 600,334 588,596 588,519 Lands of the Navajo Nation 26,449,393 23,999,556 22,557,749 21,700,587 Lands of the Uintah and Ouray Reservation 2,758,744 2,503,220 2,352,835 2,263,431

Louisiana 42,035,202 38,461,163 36,496,707 35,427,023 Maine 13,360,735 12,511,985 12,181,628 12,104,747 Maryland 17,447,354 15,842,485 14,902,826 14,347,628 Massachusetts 2,251,173 2,119,865 2,076,179 2,073,942 Michigan 56,854,256 51,893,556 49,106,884 47,544,064 Minnesota 27,303,150 24,868,570 23,476,788 22,678,368 Missi ssippi 67,312,915 61,158,279 57,570,942 55,462,884 Missouri 28,940,675 26,790,683 25,756,215 25,304,337 Formatted Table

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...(b) If implementing interstate trading, then the Administrator will use the sum of a covered group of
states’ S tates’ mass - based emission goals as the aggregate mass

based emission goal. Montana 13,776,601 12,500,563 11,749,574 11,303,107 Nebraska 60,975,831 55,749,239 52,856,495 51,266,234 Nevada 25,453,173 23,095,610 21,708,108 20,883,232 New Hampshire 22,246,365 20,192,820 18,987,285 18,272,739 New Jersey 4,461,569 4,162,981 4,037,142 3,997,579 New Mexico 18,241,502 17,107,548 16,681,949 16,599,745 New York 14,789,981 13,514,670 12,805,266 12,412,602 North Carolina 15,076,534 14,072,636 13,652,612 13,523,584 North Dakota 35,493,488 32,932,763 31,741,940 31,257,429 Ohio 88,512,313 80,704,944 76,280,168 73,769,806 Oklahoma 47,577,611 43,665,021 41,577,379 40,488,199 Oregon 9,097,720 8,477,658 8,209,589 8,118,654 Pennsylvania 106,082,757 97,204,723 92,392,088 89,822,308 Rhode Island 3,811,632 3,592,937 3,522,686 3,522,225 South Carolina 31,025,518 28,336,836 26,834,962 25,998,968 South Dakota 4,231,184 3,862,401 3,655,422 3,539,481 Tennessee 34,118,301 31,079,178 29,343,221 28,348,396 Texas 221,613,296 203,728,060 194,351,330 189,588,842 Utah 28,479,805 25,981,970 24,572,858 23,778,193 Virginia 31,290,209 28,990,999 27,898,475 27,433,111 Washington 12,395,697 11,441,137 10,963,576 10,739,172 West Virginia 33,505,657 30,571,326 28,917,949 27,986,988 Wisconsin 62,557,024 56,762,771 53,352,666 51,325,342 Wyoming 38,528,498 34,967,826 32,875,725 31,634,412 * * The values in this table are annual amounts; the mass goal for each multi

- year compliance period is the annual value multiplied by the number of years in the compliance period. Each emission goal includes the renewable energy set

- asides and output

- based set

- asides (the output

- based set

- aside s are zero in the first compliance period). The first compliance period goals also include the early action Clean Energy Incentive Program set

aside. Formatted Table(c) The renewable energy set

- aside for each state S tate covered by the federal mass

- based emissions trading plan shall must reserve five 5 percent from the State’s annual allo wances prior to allocation of that year’s allowances to facilities. The renewable energy set

- asides are as follows: specified in Table 2 of this subpart. **Table**

**___ 2 to**  **to Subpart MMM of Part 62 --**  **Statewide Renewable Energy Set**  **- aside**  **(short tons)**
**Interim Period Final Period** 

**State Compliance**  **Period 1 2022**  **- 2024**  **Compliance Period 2**  **2025 -**  **2027 Complianc**  **e Period 3**  **2028 -**  **2029 Final**  **compliance**

**periods 2030**  **- 2031**  **and thereafter**  Alabama 3,308,224 3,045,949 2,910,799 2,844,024 Arizona 1,759,462 1,618,597 1,545,311 1,508,538 Arkansas 1,801,634 1,647,676 1,562,687 1,516,132 California 2,675,005 2,504,042 2,436,844 2,420,506 Colorado 1,789,266 1,632,724 1,544,591 1,495,020 Connecticut 377,789 355,423 347,754 347,076 Delaware 267,418 248,155 239,214 235,591 Florida 5,969,024 5,537,734 5,336,809 5,254,735 Georgia 2,712,897 2,492,754 2,376,741 2,317,342 Idaho 80,776 76,141 74,653 74,643 Illinois 4,019,805 3,656,247 3,446,097 3,323,858 Indiana 4,600,539 4,185,017 3,945,079 3,805,692 Iowa 1,520,418 1,380,771 1,299,099 1,250,907 Kansas 1,338,186 1,214,789 1,142,405 1,099,541 Kentucky 3,837,868 3,484,943 3,278,345 3,156,306 Lands of the Fort Mojave Tribe 31,844 30,017 29,430 29,426

Lands of the Navajo Nation 1,322,470 1,199,978 1,127,887 1,085,029 Formatted Table

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...Lands of the Uintah and Ouray Reservation 137,937 125,161 117,642 113,172

Louisiana 2,101,760 1,923,058 1,824,835 1,771,351 Maine 112,559 105,993 103,809 103,697 Maryland 872,368 792,124 745,141 717,381 Massachusett s 668,037 625,599 609,081 605,237 Michigan 2,842,713 2,594,678 2,455,344 2,377,203 Minnesota 1,365,158 1,243,429 1,173,839 1,133,918 Mississippi 1,447,034 1,339,534 1,287,811 1,265,217 Missouri 3,365,646 3,057,914 2,878,547 2,773,144 Montana 688,830 625,028 587,479 565,155 Nebraska 1,112,318 1,009,641 949,364 913,637 Nevada 753,827 703,632 682,631 676,179 New Hampshire 223,078 208,149 201,857 199,879 New Jersey 912,075 855,377 834,097 829,987 New Mexico 739,499 675,734 640,263 620,630 New York 1,774,674 1,646,638 1,587,097 1,562,871 North Carolina 3,048,792 2,787,462 2,642,825 2,563,312 North Dakota 1,272,659 1,154,781 1,085,405 1,044,162 Ohio 4,425,616 4,035,247 3,814,008 3,688,490 Oklahoma 2,378,881 2,183,251 2,078,869 2,024,410 Oregon 454,886 423,883 410,479 405,933 Pennsylvania 5,304,138 4,860,236 4,619,604 4,491,115 Rhode Island 190,582 179,647 176,134 176,111 South Carolina 1,551,276 1,416,842 1,341,748 1,299,948 South Dakota 211,559 193,120 182,771 176,974 Tennessee 1,705,915 1,553,959 1,467,161 1,417,420 Texas 11,080,665 10,186,403 9,717,567 9,479,442 Utah 1,423,990 1,299,099 1,228,643 1,188,910 Virginia 1,564,510 1,449,550 1,394,924 1,371,656 Washington 619,785 572,057 548,179 536,959 West Virginia 3,127,851 2,838,139 2,667,633 2,566,267 Wisconsin 1,675,283 1,528,566 1,445,897 1,399,349 Wyoming 1,926,425 1,748,391 1,643,786 1,581,721( d ) The output

- based set

- aside for each state S tate under this subpart, beginning in compliance period 2, shall 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

. (2) (d)

. The output

- based set

- asides are as follows: specified in Table 3 to this subpart.

**Table &&&.**  **3 to Subpart MMM of Part 62**  **-- .**  **Statewide Output -**  **based Set**  **- aside**  **(short tons) State**  Allowances in Output

- based Set

aside (short tons) Alabama 4,185,496 Arizona 4,197,813 Arkansas 2,102,538 California 8,458,604 Colorado 1,348,187 Connecticut 1,090,811 Delaware 649,190 Florida 12,102,688 Georgia 3,563,104 Idaho 246,638 Illinois 1,598,615 Indiana 1,106,150 Iowa 492,510 Kansas 62,257 Kentucky 288,730 Lands of the Fort Mojave Tribe 248,127 Lands of the Navajo Nation 0 Lands of the Uintah and Ouray Reservation 0 Louisiana 2,207,879 Maine 563,925 Maryland 103,762 Massachusetts 2,439,991 Michigan 2,105,786 Minnesota 909,724 Mississippi 3,132,671 Missouri 815,210 Montana 0 Formatted Table

Formatted: Left Formatted: Right Formatted: Left Formatted: Right Formatted: Left Formatted: Right Formatted: Left Formatted: Right Formatted: Left Formatted: Right Formatted: Left Formatted: RightNebraska 144,635 Nevada 2,326,529 New Hampshire 542,721 New Jersey 3,413,100 New Mexico 627,085 New York 3,815,381 North Carolina 2,120,178 North Dakota 0 Ohio 1,757,326 Oklahoma 3,121,167 Oregon 1,291,027 Pennsylvania 4,392,931 Rhode Island 778,307 South Carolina 1,029,366 South Dakota 130,831 Tennessee 632,949 Texas 15,990,657 Utah 825,586 Virginia 3,011,811 Washington 1,383,060 West Virginia 0 Wisconsin 1,181,175 Wyoming 45,114

(e)(1) The Clean Energy Investment Program Set

- Aside for each state S tate covered under this subpart shall must contain an amount of allowances equal shown in T able 4 to the state’s pro
rata this subpart , which must reserve a share of 300 million 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** of CO 2 , which shall be drawn from the mass budget for the first compliance period of all of the affected EGUs in a state on a unit

- by

- unit pro rata basis. **)**

**State** Allowances in Early Action Set

aside Formatted: Centered, Indent: First line: 0", Line spacing: single Formatted: Font: Bold Formatted: Font: Bold(short tons) Alabama 3,122,306 Arizona 1,719,618 Arkansas 2,187,230 California 218,846 Colorado 2,223,192 Connecticut 69,415 Delaware 138,392 Florida 3,230,248 Georgia 2,755,623 Idaho 14,929 Illinois 5,968,721 Indiana 5,754,076 Iowa 2,191,183 Kansas 2,115,630 Kentucky 4,952,862 Lands of the Fort Mojave Tribe 5,885 Lands of the Navajo Nation 1,623,066 Lands of the Uintah and Ouray Reservation 175,509 Louisiana 1,497,428 Maine 20,739 Maryland 972,775 Massachusetts 170,471 Michigan 3,727,861 Minnesota 2,002,903 Mississippi 357,307 Missouri 3,771,322 Montana 1,310,344 Nebraska 1,481,695 Nevada 336,288 New Hampshire 107,798 New Jersey 446,005 New Mexico 823,049 New York 557,771 North Carolina 2,674,590 North Dakota 2,150,635 Ohio 4,788,372 Oklahoma 2,067,006 Oregon 154,353 Pennsylvania 5,039,346 Rhode Island 35,674 South Carolina 1,652,802 South Dakota 264,207 Tennessee 2,178,084Texas 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 subparagraph (3), paragraph (e) (3) of this section , upon application of a project proponent that meets the requirements of 62.16245(a), except as may be prescribed by the Administrator in a future action. In order to receive a distribution, the project proponent must establish a general account in the tra cking system as provided in 62.16320(c). (3) Projects eligible for distribution of allowances from this set

- aside must meet each of the following criteria: criteria in paragraphs (e)(3)(i) through (ii i ) of this section. All categories of resources other th an 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 T he creditable generation or energy savings from the project must occur in calendar years 2020 or 2021; and (iii) generation G eneration or energy savings must be from one of the following types of sources capable of revenue

- quality metering: (A) Onshore wind; (B) solar S olar ; or (C) demand D emand

- side EE Note to paragraph (e)(3): All categories of resources other than those listed in paragraphs (e)(3)(iii)(A) and (B), and all provisions of this subpart relating to such resources, are not available or applicabl e in states where this subpart has been promulgated as a federal plan pursuant to section 111(d)(2) of the Act

. **§ 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, CO 2 allowances will be allocated, for the multi

- year compliance periods in the Interim Period beginning in 2022 and the Final Period beginning in 2030, as provided by the Administrator

. in a Formatted: Indent: First line: 0.5"

Formatted: No underlinenotice of data availability or through this subpart (if applicable)

. Providing an allocation to an entity in such notice does not constitute a as an applicability determination that the entity is an affected EGU, and not providing an allocation to an entity in such notice does not co nstitute a determination that the entity is not 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 two consecutive calendar years, then such affected EGU will

no t be allocated the CO 2 allowances provided by the Administrator in such 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 CO 2 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 Administr ator in the notice of data availability issued by the Administrator

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 CO 2 allowancesprovided 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 CO 2 allowances that would otherwise have been allocated to such affect ed 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 e nergy set

- asides. (i) By December 1, 2021 and December 1 of each year thereafter, the Administrator will calculate and allocate the CO 2 allowance allocation to each approved Renewal Energy project in a State, in accordance with §62.16245(a)(2) through ( 6 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 CO 2 allowance allocation to each affected EGU in a State, in accordance with §62.16245(a)( 7 6 ) and ( 8 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 s et

- asides

. (i) By November 1 of the first year of each compliance period beginning in 2025, and each compliance period thereafter, Formatted: No underlinethe Administrator will calculate and allocate the CO 2 allowance allocation to each eligible affected EGU in a State, in accordance with §62.16245(b)(3), for the generation period of the applicable calculation deadline under this paragraph. (ii) By November 1 of the first year of each compliance period beginning in 2025, and each compliance period thereafter, the Administrator will calculate and allocate the CO 2 allowance allocation to each affected EGU in a State, in accordan ce 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 CO 2 Allowances.

a llowances. (1) For each compliance period in 2022 and thereafter, if the Administrator determines that CO 2 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 inparagraphs (c)(2) through (5) of this section . The situations for the Admin istrator to act according to the procedures in paragraphs (c)(2) through (5) are if : (i)(A) The recipient is not actually an affected EGU under §62.16210 as of January 1, 2022 and is allocated CO 2 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 CO 2 allowances for such compliance peri od 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 CO 2 allowances the CO 2 allowances allocated under paragraph (a) of this section, or under a provision of a s tate allowance distribution methodology approved under subpart UUUU of part 60 of this chapter, were allocated for such compliance period. (ii) The rec ipient is not actually an affected EGU under §62.16210 as of January 1 of such compliance period and is allocated CO 2 allowances for such compliance period or, in the case of an allocation under a provision of a s tate allowance distribution methodology app roved under subpart UUUU of part 60of this chapter, the recipient is not actually an affected EGU as of January 1 of such compliance period and is allocated CO 2 allowances for such compliance period that the a s tate allowance distribution methodology prov ides 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 CO 2 allowances under §62.16325. (3) If t he Administrator already recorded such CO 2 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 CO 2 allowances were recorded an amount of CO 2 allowances allocated for the same or a prior compliance period equal to the amount of such already

- recorded CO 2 allowances. The authorized account representative shall must ensure that there are sufficient CO 2 allowances in such account for completion of the deduction. (4) If the Administrator already recorded such CO 2 allowances under §62.16325 and if the Administrator makes t he determination under paragraph (c)(1) of this section after making deductions for the facility that includes such recipientunder §62.16340(b) for such compliance period, then the Administrator will not make any deduction to take account of such already

- recorded CO 2 allowances. (5)(i) With regard to the CO 2 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 CO 2 allowa nces to the renewable energy
set

- aside for such compliance period for the State from whose CO 2 allowances the CO 2 allowances were allocated; or (B) If the State has a state allowance distribution methodology approved under subpart UUUU of part 60 of this

c hapter covering such compliance period, then include such CO 2 allowances in the portion of the CO 2 allowances that may be allocated for such compliance period in accordance with such state allowance distribution methodology. (ii) With regard to the CO 2 all owances 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)( 1 2 ) and ( 2 3 ) of this section for a re cipient under paragraph (c)(1)(ii) of this paragraph section , the Administrator will:(A) T ransfer such CO 2 allowances to the renewable energy
set

- aside for such compliance period; or (B) I f 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 CO 2 allowances in the portion of the CO 2 allowances that may be allocated for such complian ce period in accordance with such state allowance distribution methodology. (iii) With regard to the CO 2 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 de ducted 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 paragraph section , the Administrator will transfer such CO 2 allowances that were from the renewable energy set

- aside back to the renewable energy set

- aside, or that were from the output based set

- aside to the output

- based set

aside , respectively , for such compliance period. **§62.16245 How are set -**  **aside allowances allocated?** (a)(1) Renewable Energy Set e nergy s et

- aside . The Administrator will establish a renewable energy set

- aside as set forth in §62.16235(c), and allocate CO 2 allowances from the set

aside for each State and each year of a control co mpliance period as outlined in this section.(2) Eligible Renewable Energy Capacity. r enewable e nergy

c apacity. To be eligible to receive renewable energy set

- aside allowances, an eligible resource that must meet each of the requirements in paragraphs ( a)(2) ( i) through (v) of this section : . Any resource that does not meet the requirements of paragraphs (a)(2)(i) through (v) of this section cannot receive
set

- aside allowances. (i) The resource must be a renewable energy resource that falls into one of the following categories of resources: on

shore utility scale wind, utility scale solar, concentrated solar power 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 nameplat e capacity prior to the uprate. Set

aside 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 capacit y 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 pe rmit is eligible to be issued set

- aside allowances. (iii) The resource must be located in the mass

- based
state S tate for which the set

- aside has been designated. (iv) The resource must be connected to, and delivers energy to or saves electricity, on the electric grid in the contiguous United States. (v) The resource must not have received e mission r ate

c redits ( ERCs ) for any period of time for which it receives set

aside allowances. (vi) Any resource that does not meet the requirements of this subpart can not receive set

- aside allowances. (3) Process for issuance of set

- aside allowances. The process and requirements for issuance of set

- aside allowances are set forth in paragraphs ( a)(3) ( i) through (x ). ) of this section

. (i) Eligibility application. To receive set

- aside allowances, an authorized account representative of an eligible resource must submit an eligibility application to the Administrator that demonstrates that the requirements of §62.16245 paragraph (a)(2) of this section are met and, demonstrates that the following requirements are met: Formatted: Font: Courier New(A) Identification of the authorized account representative of the eligible resource, including the authorized account representative’s name, address, e

- mail address, telep hone number, and allowance tracking system account number

. ; and (B) Identification of the eligible resource(s), including the physical location of the electric generating eligible resource; contact information for the owner or operator of the electric gener ating eligible resource, if different from the authorized account representative and designated representative; generator prime mover and technology type; generator nameplate capacity ; (if applicable) ; generator category (e.g., wholesale generator, wholesale generator also serving onsite customer load, customer

- sited distributed generator ) (if applicable ) ; facility and generating unit IDs (EIA ORIS Code, Facility Registration System (FRS) Code, if appli cable ) (if applicable ) ; the control area, balancing authority, ISO , con ditions as defined in § 62.16375 (if applicable) , or RTO regional transmission organization in which the generator is located ; (if applicable) ; and a copy of the most recent filing of a copy of the generating facility’s U.S. Energy Information Agency’s Annual Electric Generator Report Form EIA

- 860
. (if applicable)

. (ii) Renewable energy providers must open a general account per the requirements in §62. 16305 16320 (c) , and submit a project application for renewable energy set

- aside allowances to theAdministrator 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 generat ion years, these projections must be received by June 1 of the year prior to the generation year in question. The project application shall must contain the following information: (iii ( A ) Projection of the project’s annual renewable energy generation in MW h. ( iv B ) Documentation of the methodology, data facilities, and assumptions used to project the project’s annual renewable energy generation. ( v C ) A certification that the eligibility application has only been submitted to the Administrator or pursuant to an EPA

approved multi

- state S tate approach where states S tates are providing for joint issuance of allowances pursuant to the authority in their individual state S tate plans. ( vi) An D ) A evaluation, measurement, and verification ( EM&V ) plan. ( vii 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 ve rifier to the Administrator.( viii 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 pla n have been implemented as described in the eligibility application. ( ix G ) The following statement, signed by the authorized account representative of the eligible resource: ( 1 ) “ I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my personal knowledge and/or inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements an d 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 possibilit y of fine or imprisonment

. . ” ( x 2 ) [Reserved] ( H ) Any other information required by the Administrator. (4) Deficient Applications. An application is deficient and will be returned by the Administrator if it fails to meet the requirements set forth in (a)(3) of this section. A revised Formatted: Font: Italicapplication that is submitted after being returned for failure to meet the requirements of this subpa rt must be submitted by DD/MM of the year prior to the generation year for which set

aside allowances are requested. (5) Monitoring and Verification. ( 4 ) Monitoring and

v erification

. 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) an A measurement and verification ( M&V ) report. (ii) a 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 t he Administrator. ( 6 5 ) Allocation of Renewable Energy Set

- Aside Allowances. The Administrator will enter the projected generation from each approved project into a pool of projects for that state S tate that will receive set

- asides for a generation year. (i) The Administrator will distribute state renewable energy set

- aside allowances for a generation year pro - rata, with the number of allowances distributed to each project prorated according to the its percentage of the total approved projected MWhs for that state S tate 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 gr eater 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 three 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. ( 7 6 ) Surplus Renewable Set r enewable s et

- aside Allowances a llowances

. If, after completion of the procedures under paragraph (a)( 7) 5 ) of this section for each compliance period, any unallocated CO 2 allowances remain in the renewable energy set

- aside for the State for such generation year, the Administrator will allocate the amount of CO 2 allowances in a pro rata fashion on the same distribution basis as their initial allocations were made to each af fected EGU that: is in theState; is allocated an amount of CO 2 allowances in the notice of data availability issued under §62.16240(a)(1); and continues to be allocated CO 2 allowances for such control compliance period in accordance with §62.16240(a)(2). ( 8 7 ) Notice of Surplus Renewable Energy Set s urplus

r enewable e nergy s et

- aside Allowance Distribution

. a llowance d istribution. The Administrator will make publicly, public the amount of CO 2 allowances allocated under paragraph (a)( 7 6 ) of this section for such generation year period to each affected EGU eligible for such allocation. (b)(1) Output

- based Set s et

- aside. The Administrator will establish an output

- based set

- aside beginning in compliance period 2, and allocate CO 2 allowances from the set

- aside for each State and each year of a compliance period as set forth in §62.16235(c). (2) Unit Eligibility e ligibility . To be eligible to receive output

- based set

- aside allowances, affected EGUs must meet the following eligibility requirements: (i) The affected EGU must be a natural gas combined cycle unit

. ; (ii) The affected EGU must be located in the mass

- based State for which the set

- aside has been designated

. ; and(iii) The affected EGU’s average capacity factor in the preceding compliance period was above 50 percent based on net summer capacity and net generation. (3) Allocation of Output o utput

- based Set

- Aside Allowances s et

- a side a llowances . The Administrator will allocate output based set

- aside allowances for each elig ible 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 set

aside as the unit’s average net gener ation 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 ea ch compliance period beginning in 2025. The notice of the net summer capacity and net generation data used, and the resulting allocations, shall must allow 30 days for public comment on the data and allocations, until August 31 of the same year.(iv) The Ad ministrator will provide notice of the final
set

- aside allocations by November 1 of the same year. (4) Surplus Output o utput

- based Set

- Aside Allowances

. s et

a side a llowances

. If, after completion of the procedures under paragraph (b)(3) of this section for each compliance period, any unallocated CO 2 allowances remain in the out

- put based set

- aside for the State for such generation period, the Administrator will allocate the amount of CO 2 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 CO 2 allowances in the notice of data availability issued under §62.16240(a)(1); an d continues to be allocated CO 2 allowances for such control compliance period in accordance with §62.16240(a)(2
. )
. (5) Notice of Surplus Output s urplus o utput

- based Set s et

aside. The Administrator will notify the public, through the promulgation of the notices of data availability described in §62.16240 (b)(1 )(iii), (iv), ) and ( v 2 ) , of the amount of CO 2 allowances allocated under paragraphs (b)(3) and (4) of this section for such control compliance period to each affected EGU eligible for such allocation. **§ §62.16250 What is the process for revocation of qualification**  **status of an eligible resource?** (a) If an eligible resource is found to not meet therequirements of §62.16260 in the mass CO 2 M ass - based trading
program, T rading P rogram, 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 err or 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 set

aside allowances. (d) In the event of an intentional misrepresentation, or repeated instances of error or misstatement, in program submissions, by the authorized account representative of the eligible resource, the Administrator may prohibit the eligible resource from any further eligibility t o 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 reportfor which set

- aside allowances have been issued, the Administrator may adjust the number of set

- aside allowances issued in a subsequen t 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 shall must submit to the Administrator within 30 days a number of set

- aside allowances necessary to correct the error or misstatement. Failure to meet this requirement will result in prohibition of the authorized account representative for the eligible resource from further participation in the program, unless reauthorizedat 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 Admi nistrator determines set

aside allowances have been improperly issued, based on a misrepresentation or misstatement in an eligibility application or M&V report. The Administrator may also freeze the general account of a a n 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 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 iss ued for the ineligible eligible resource, the delegated representative of an eligible resource shall 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 repea ted error or misstatements in submitted M&V reports. (iii) In the case of an intentional misrepresentation in a submitted M&V report. **Evaluation Measurement and Verification Plans, Monitoring and Verification Reports, and Verification** **§ §**  **62.16260 What are the requirements for evaluation measurement**  **and verification plans for eligible resources?** (a) (a) EM&V plan requirements. Any EM&V plan submitted in support of the issuance of an 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. (i) The generation data is physically measured on a continuous basis using a revenue

- quali ty meter, which shall

mean mean s a meter used by a control area operator for financialsettlements, 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, unl ess 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, S tate ; (C) The nameplate capacity of the individual units being aggregated is each less than 150 kW, and units collectively donot exceed a total nameplate capacity of 1 MW when aggregated, or alternative requirements approved by the EPA in connection with the sp ecific state S tate 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 ar ea 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 p ursuant to the relevant state S tate 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 ena ble 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) 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 t o 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 S tate plan pursuant to which that EM&V plan is submitted. (2) For a renewable energy resource with a nameplate capacity of less than 10 kW and that does not have a meter, each EM&V plan must require that the following requirements in paragraphs (c)(2)(i) through (vii) of this section are met. (i) Metered data are unavailable. (ii) At least 1 MW of net energy output is generated to the distribution or transmission system over a continuous 365

- day period.(iii) The generation data may not be aggregated, unless the following provisions are met: (A) All of the generating units have the same essential generation characteristics; (B) All of the generating units are located in the same
state S tate ; (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 S tate 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 irra diance, 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.(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 set

aside allowance is only based on generation transferred from the eligible resource to the transmission or distrib ution 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 S tate plan pursuant to which that EM&V plan is submitted. (3) For qualifying qualif ied biomass feedstocks used ,, , in addition to the requirements of paragraphs paragraph (c)(1) or (2) of this section, whichever section is applicable, each EM&V plan must demonstrate that the requirements approved by the Administrator EPA for that biomass feeds tock and its associated biogenic CO 2 in connection with that state plan have been met. (4) For a waste

— to

- energy resource, in addition to the requirements of paragraphs paragraph (c)(1) or (2) of this section, as applicable, and paragraph (c)(3) of this section, each EM&V plan must specify: (i) the The total net energy generation from the resource in MWh; (ii) the T he method for determining the specific portion ofthe total net ener gy output from the resource that is related to the biogenic portion of the waste; and (iii) the T he net energy output is measured with the relevant method approved by the EPA in connection with the specific state S tate plan pursuant to which that EM&V plan i s submitted demonstrate that the requirements approved by the EPA in connection with that state S tate 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) and (ii), through ( iv ) of this section, as applicable, and any other requirements approved by the EPA in connection with the specific state plan pursuant

. (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. 16345 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 CO 2 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 CO 2 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 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 factors may be used in calculati ng the electricity savings, including measures such as conservation voltage reduction andvolt/VAR optimization. (7) Each EM&V plan that addresses for an EE program , EE project, or EE measure must specify how each of the following requirements in paragraphs (c)(7)(i) through (x) of this section will be met in quantifying the electricity savings from that EE
program , EE project , or EE measure : . (i) All electricity savings must be quantified on an ex poste

- post basis, which means after the electricit y savings have occurred, and must 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 based on projects estimates of electricity MWh savings that have are generated prior to implementing the subject EE program, EE project, or EE measure , and that are not yet occurred quantified using EM&V methods and procedures

. (ii) All electricity savings must be quantified and verified based on methods and procedures and methods detailed in an industry best

- practice EM&V protocol

. or guideline

. Each EM&V plan must include a demonstration of how the specific best practices

- practice protocol or guideline was selected and will be applied to the specific EE APM P program, EE project, or EE

measure covered in the E E M &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) They have Have gone through a rigorous and credible peer review process and are widely that shows the applicable methods to be valid through empirical testing; and (B) Have been accepted as best practices and approved for

use within the energy efficiency industry, and by identifiable state regula tory commissions. Examples of such protocols and guidelines that may be provided in EM&V guidance issued by the Administrator will be acceptable. (B) They result in accurate estimates of electricity savings that have at least 80 percent confidence intervals with end points that are no more than +/

- 10 percent of the estimate. (iii) All electricity savings must be based on an actual EE measure and must be counted only for the period that the EE measures are actually generating electricity savings. (i v) All electricity savings must be calculated 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 o wner 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 beacceptable. The EM&V plan must specify the reason the specific common practice baseline CPB was selected for that EE measure , which must include an analysis of the appropriateness of that CPB for the EE measure 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

- of

sale rebate ), ); (C) Local consumer and market characteristics , ; (D) Applicab le 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. (v (iv ) All electricity savings must be quantified by
app lying one or more of the following methods: project

- based measurement and verification ( PB

- MV ), , comparison group approaches, or deemed savings. (A) If project

- based measurement and verification is used, the EM&V plan must specify that explicit verification of the EE project or EE measure will occur within the first year of its Formatted: Indent: First line: 0.5"implementation (e.g., using phone or mail surveys, document review, site inspections, or spot or short

- term metering). (B) If a comparison group approach is used, then the EM&V plan must determine 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 random randomized control trials and
quas i

- experimental methods using nonparticipants. , 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

. ( C 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 specify that also specify the name and Web address of the technical r eference manual (TRM) in which all “ deemed ” electricity savings must values will be documented in a technical reference manual that has been subject to rigorous peer review and is located on . Prior to use in an EM&V plan, all TRMs must undergo a review proc ess 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 res ponses are made publicly availabledatabase that is reviewed and . 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 subs equently updated in the

same manner at least every 3 three years. The database TRM must indicate, for each value, the technology or subject EE measure upon which it is based , the associated electricity savings value, the conditions for under which the value ca n be applied , ( including the climate zone, building type, manner of implementation, applicable end udes uses , operating conditions, and effective useful life , any peak load impacts, any ), and the manner in which the electricity savings value was quantified , which must include applicable engineering algorithms used to calculate electricity savings, and any , source documentation, specific assumptions, and other relevant material data to support the calculation quantification of savings in specific from the subje ct EE measure. ( vi v ) All electricity savings EE program s, 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 , EEproject, or EE measure , any expected variability in its electricity savin gs , and (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 by 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 four year intervals for building energy codes and product standards

. ; (B) Every one, two or three 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 type, the magnitude and variability of electricity savings, factors listed in paragraph (c) (7)( v) of this section; and experience with the
APMP. (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

.(vii) The following factors and their impact on the (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 from the specific EE measure that is the subject of the specific EM&V plan must be addressed in the EM&V plan:

. (A) The effects of any changes in independent variables that will affect the factors on reported electricity savings must be described ( i.e., factors that are not directly related to the EE measure, such as weather, occupancy, and /or 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 an evaluation the application of the EE measure EM&V methods , an industry best

- practice persistence study, deemed estimates of effective useful life, or a combination of all of these three

. ( 1 ) If deemed estimates of effective useful life estimates are used, then they must specify the date by which the EE measure will have stopped stop saving electricity is specified

. ( 2 ) If industry best

- practices persistence studies are used , to modify an effective

- useful

- life value, then they must Formatted: Indent: First line: 0.5"

Formatted: Font: Italic Formatted: Font: Italic Formatted: Font: Italic

Formatted: Font: Italic Formatted: Font: Italic Formatted: Font: Italicbe conducted at least every 5 years. (C) No The potential sources of double counting of the electricity savings may occur , and the EM&V plan must include documentation of the associated steps taken to avoid double counting. The EM&V may specify that the following procedures will be taken to avoid double counting at the EE measure: (1) For programs for avoiding and projects correcting for it, such as: ( 1 ) For an EE program or EE project with identified consumers, EE actions ( participants, track the type and number of EE measures implemented ) will be tracked at the utility

customer level. ( 2 ) For programs an EE program or EE project without identified consumers participants , such as point

- of

- sale rebates and retailer or manufacturer incentive programs, track applicable vendor, retailer, and manufacturer data will be tracked

. ( 3 ) Consumer

- level ) For EE program s (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 will be used to identify avoid and correct for duplication double counting that
may occur across the two; and ( 4 ) For EE programs with “trackable” consumers and across Formatted: Font: Italic Formatted: Font: Italic Formatted: Font: Italic

Formatted: Font: Italic Formatted: Font: Italicnon - identified participants and those without (such as retail incentives to purchase energy

- efficient equipment), use EE
program projects such as private

- sector transactions for projects sponsored by an ESCO 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

. (4) Instances where tracked consumer activity is likely to be double counted with upstream activity wil l be identified and the estimated overlap subtracked from the electricity savings claimed. (D) If the EE measure involves the installation of identifiable measures, the EM&V plan must specify the manner in which ( D) The EE savings verification approaches f or ensuring that the EE measure has measures have been properly installed, is operating as intended, and therefore has the potential to save electricity , including how verification will occur be carried out within the first year of implementation of the EE program , EE project, or EE measure , using si te best

- practice approaches, such as physical inspections at a customer premises , phone and mail surveys, and reviews of sales receipts and other best

- practice techniques

. documentation. If such approaches are documented in EM&V guidance issued by the Administrator, they will be treated as acceptable.(E) Interactive The i nteractive effects of EE program s, EE projects, or EE measures on electricity usage, which are increase s or decreases in electricity use usage at a site an end

use facility or premises that occurs outside of the specific end

- uses (s) targeted by a specific EE program, project, or

measures. 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). ( viii vii ) The EM&V plan must specify how the accuracy an d 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 evaluate quantify the electricity savings , . It must also discuss the methods approaches that will be used to control all relevant types of bias and to minimize the potential for systematic and random error, and assess as well

as the potential effects of program - or project

- specific circumstances in which such bias and error specified are likely to arise. Ap proaches to minimizing bias and error are provided in the EM&V plan guidance that may be issued by the Administrator will be acceptable

. ( ix viii ) If sampling will be used to quantify the electricity savings or the from an EE measure, program, then the MWh estimates derived from sampling must have at least 80 90percent 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. (x) Any (ix) All data sources and key assumptions and data

sources used to quantify electricity savings must be described in the EM&V plan. ( xi x ) Any additional information necessary to demonstrate that the electricity savings were appropriately quantified a nd 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] **§ 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 accordance with the requirements of §62.16265 , in support of the issuance of an a set

- aside allowance that can be used in accordance with § 62.16240, must meet t he requirements of this section. (b) General M&V report criteria. Each M&V report must include the following: information in paragraphs (b)(1) and (2) of this section. i (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). ( ii 2 ) For each M&V report submitted: (A) identification ( i ) I dentification of the time period covered by the M&V report , ; ( B) a 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 , ; ( C) documentation iii ) D ocumentation (including data) of theenergy generation and/or electricity savings from any activity, projec t, measure , resource , or program addressed in the EM&V report, quantified and verified in MWh for the period covered by the M&V report, in accordance with its EM&V plan, and based on

ex - post energy generation or savings , ; (D) documentation ( iv ) D ocumentati on 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 eligib ility 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 (E) documentation ( v ) D ocumentation of any change in ownership interest of the qualifying eli gible resource (including the date of the change). ( d 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 informationsubmitted 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) [R eserved] **§62.16270 Verification**  **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 materi al data discrepancies, and whether the Formatted: Font: Not Boldsubmittal 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 s tatement, signed by the accredited independent verifier:

“ I certify under penalty o f 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 knowle dge 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] (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 accordancewith § 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 duplic ative of a resource used to meet emission standards or a state measure in another approved state S tate plan

. ; (3) The eligible resource exists or the practice 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 re newable energy certificate tracking system ). ) ; and (6) Any other information required by the Administrator or that the accredited independent verifier finds, in its professional opinion, is necessary to assess the adequacy and validity of information and data supplied by the authorized account representative. (c) A verification report included as part of a a n M&V report must, at a minimum, describe the review conducted by the accredited independent verifier and verify thefollowing: 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 ch eck 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

es timate of the maximum generation potential of the qualified renewable energy resource, based on, at a minimum, its maximum nameplate capacity in MW and the number of days since the prior cumulative meter reading was entered in the allowance tracking system . If the data entered exceeds the estimated technically feasible generation, then the reported data and the estimate must be analyzed in the verification report. (ii) For all electricity generated or saved, the accredited independent verifier must describe the likely source of any datadiscrepancy 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 Accreditation of Independent Verifiers. §**  **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 shall include include s a demonstration by the verifier that it meets the requirements in paragraph ( d). c ) of this section

. ( d c ) Independent verifiers must meet each of the requirements in paragraphs ( d 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:(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 Ad ministrator’s
state’s Rate CO 2 Mass

- based Tradi ng 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 with an approved EM&V plan; preparation of a verificationopinion, 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 subcontracto rs (collectively, accredited independent verification team) and demonstrate that they meet the requirements of paragraph (c)(1) of this section §62.16275(d)(1).

. Once accredited, only the accredited independent verification team identified in the accredita tion application and accredited by the state S tate 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 v erification 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 t o 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 CFRpart 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 mainte nance of, for any parties that it employs, professional liability insurance, as defined in 31 C.F.R. 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 shall must disclose the level of professional liability insurance they possess when entering into contracts t o provide verification services pursuant to thi s regulation. ( e d ) Requirements for maintenance of accreditation status. (1) Accredited independent verifiers must meet the requirements of section **§** 62.16280 when providing verification services for a a n 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**  **of accredited independent**  **verifiers must follow to avoid conflict of intere st?** (a) Accredited independent verifiers must not provide verification services for any eligible resource for which it has a conflict of interest or ( 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 the the y seek to provide a verification re port . ; (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 a a n 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

- asideallowance issuance, or the number of set

- aside allowances issued ). ) ; (5) Accredited independent verifi ers 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 deri vatives

. ; (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 th e 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 wi th the subject of the report. (b) A contract with an eligible resource for the provision of verification services shall will not constitute a conflict of interest COI
. (c) Verification reports must include an attestation by the accredited independent verif ier 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 conflict of int erest COI related to the eligible resource, as specified in §62.16280 paragraph (a ). ) of this section

. If a conflict of interest 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) below, of this section , then an accredited independent verifier may propose to the Administrat or steps that will be taken to eliminate the conflict of interest COI , which shall 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 fo r 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 shall must disclose to the Administrator all information necessary for the Administrator to evaluate a potential conflict of interest COI (including information concerning its ownership,past and current clients, related entities, as well as any other facts or circum stances that have the potential to create a conflict of interest COI ). (f) Accredited verifiers shall have an ongoing obligation to disclose to the Administrator any facts or circumstances that may give rise to a conflict of interest COI as defined in §62.1 6280 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 conflict of interest COI as defined in §62.1 6280 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 must 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 sp ecified in paragraphs (a)(1) through (4 ). ) of this section

. (1) Failure to fully disclose any issues that may lead to a conflict of interest COI with respect to an eligible resource, orother related entity, in accordance with § 62.16280(d) through (f). (2) The accredited independent verifier is no longer qualified to provide verification services. (3) Negligence in the conduct of verification activities, or neglect of responsibilities pursuant to the requirements of
§ 62.16270, § 62.16275, and § 62.16280. (4) Intentional misrepresentation of data in a verification report. **Designated Representatives §62.16290**  **How are designated representatives and alternate designated representatives authorized? What role do authorized**  **designated representatives and altern ate 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 CO 2 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 shall 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, inactio ns, or submissions, legally bind each owner and operator of the facility and each affected EGU at the facility in all matters pertaining to the CO 2 Mass

- based Trading Program, notwithstanding any agreement between the designated representative and such own ers 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 f acility 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 shall 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 shall mustact 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 shall 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 designat ed 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 af fected 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 in clude 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 aut hority to make submissions, each submissionunder the CO 2 Mass

- based Trading Program shall be made, signed, and certified by the designated representative or alternate designated representative for each Facility f acility and affected EGU for which the submission is made. Each such submission shall must include the following certification statement by the designated representative or alternate designated representative: “I am authorized to make this submission on behalf of the owners and operators of the facility or affected EGUs for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachme nts. 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 signif icant 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 f acility 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 an d**  **operators, and affected EGUs at the facility?** (a) Changing designated representative **.** The designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under §62.16305. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous designated representative before the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new designated representative and the owners and operators of the Facility f acility and th e 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 subm issions 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 representativ e, and the owners and operators of the Facility f acility 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 represen tative and any alternate designated representative of the facility or affected EGU, and the decisions and orders of the Administrator, as if the owner or operator were included in such list. (2) Within 30 days after any change in the owners and operators o f 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 shall 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),
t he designated representative or any alternate designated representative shall 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
ope rated (other than for purposes of testing by the manufacturer before initial installation) before being located at the facility, then the certificate of representation shall must identify, in a format prescribed by the Administrator, the entity from whom th e 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 facility. (2) If the change is the removal of an affected EGU, then the certificate of representation shall 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 th e 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 designate d representative or an alternate designated representative shall 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 represe ntation 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, identificati on number and nameplate capacity (in MWe, rounded to the nearest tenth) of each generator served by each such affected EGU, actual or projected date of commencement of commercial operation, net summer capacity at the affect EGU, and a statement of whether such facility is located in Indian country. If a projected date of commencement of commercial operation is provided, then the actual date of commencement of commercial operation shall must be provided when such information becomes available. (2) The name, address, e - mail 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 facili ty 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 designat ed 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 t he CO 2 Mass

- based Trading Program on behalf of the owners and operators of the facility and of each affected EGU at the facility and that each such owner and operator shall be fully bound by my representations, actions, inactions, or submissions and by any decis ion 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 agreeme nt by which I was selected to each owner and operator of the facility and of each affected EGU at the facility; and CO 2 allowances and proceeds of transactions involving CO 2 Mass

- based Trading allowances will be deemed to be held or distributed in proporti on to each holder's legal, equitable, leasehold, orcontractual reservation or entitlement, except that, if such multiple holders have expressly provided for a different distribution of CO 2 allowances by contract, then CO 2 allowances and proceeds of transa ctions involving CO 2 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. (b) Unless ot herwise 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 do cuments, 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 receiv ed, 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 objecti on 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, in action, or submission of the designated representative or alternate designated representative or the finality of any decision or order by the Administrator under the CO 2 Mass

- based Trading Program. (c) The Administrator will not adjudicate any private lega l 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 CO 2 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 submiss ion 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 requir ed under this subpart. (c) In order to delegate authority to a natural person to make an electronic submission to the Administrator in accordancewith paragraph (a) or (b) of this section, the designated representative or alternate designated representativ e, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements : in paragraphs (c)(1) through (4) of this section. (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 followin g 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, asappropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR **§** 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 40 CFR **§** 62.16315(d), I agree to maintain an e

- mail account and to notify the Administrator immediatel y of any change in my e

- mail address unless all delegation of authority by me under 40 CFR **§** 62.16315 is terminated .”. .” (d) A notice of delegation submitted under paragraph (c) of this section shall be effective, with regard to the designated representativ e 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 desig nated 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 paragr aph (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 Formatted: Font: Bold

Formatted: Font: Bold

Formatted: Font: Boldthe designated representative or alternate designated representative submitting such notice of delegation. **Monitoring, Recordkeeping, Reporting §62.16320**  **How are compliance accounts and general accounts established?**  (a) Compliance accounts **.** Upon receipt of a complete certificate of representation under §62.16305, the Administrator will establish a compliance account for the facility for which the certificate of representation was submitted, unless the facility already has a compliance account. The designated representative and any alternate designated representative of the facility shall be the authorized account representative and the alternate authorized account representative respectively of the compliance account. (b) Retirement Account a ccount s **.** (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. Formatted: Font: Not Bold(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 CO 2 allowances, by submitting to the Administrator a complete application for a general account. Such application shall must designate one and only one authorized account representative and may designate one and only one alternate authorized account representa tive 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 resp ect to CO 2 allowances held in the general account. (B) The agreement by which the alternate authorized account representative is selected shall must include a procedure for authorizing the alternate authorized account representative to act in lieu of the au thorized account representative. (ii) A complete application for a general account shall 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 tra nsmission 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 rep resentative and any alternate authorized account representativ e to represent their ownership interest with respect to the CO 2 allowances held in the general
account; (D) The following certification statement by the authorized account representative and any alternate authorized account representative: “I certify that I was selected as the authorized account representative or the alternate authorized account representative, as applicable, by an agreement that is binding on all persons who have an ownership in terest with respect to CO 2 allowances held in the general account. I certify that I have all the necessary authority to carry out my duties and responsibilities under the CO 2 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 agener al 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 authoriz ed account representative . (i) Upon receipt by the Administrator of a complete application for a general account under paragraph ( b 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
CO 2 allowances held in the general account in all matters pertaining to the CO 2 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 submi ssion by the authorized account representative

. ; and(C) Each person who has an ownership interest with respect
to CO 2 allowances held in the general account shall be bound by any decision or order issued to the authorized account representative or alterna te authorized account representative by the Administrator regarding the general account. (ii) Except as provided in paragraph ( b c )(5) of this section concerning delegation of authority to make submissions, each submission concerning the general account sh all 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 CO 2 allowances held in the general account. Each such submission sha ll 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 C O 2 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 wit h 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 forsubmitting false statements a nd 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 ( b c )(1) of this section. Notwithstanding any such change, all representati ons, 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 representat ive and the persons with an ownership interest with respect to the CO 2 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 supersedin g complete application for ageneral 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 d ate 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 CO 2 allowances in the general account. (iii)(A) In the event a person having an ownership interest with respect to CO 2 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 th e 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 CO 2 allowances in the general account, including the addition or remov al of a person, the authorized account representative or any alternate authorized account representative shall must submit a revision tothe application for a general account amending the list of persons having an ownership interest with respect to the CO 2 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 sec tion 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 ( b c )(1) of this section is received by the Administrator. (ii) Except as provided in paragraph ( b 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 auth orized 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 CO 2 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 theauthorized account representative or an y alternate authorized account representative of a general account, including private legal disputes concerning the proceeds of CO 2 allowance transfers. (5) Delegation by authorized account representative and alternate authorized account representative

. (i) An authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart. (ii) An alternate authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart. (iii) In order to delegate authority to a nat ural person to make an electronic submission to the Administrator in accordance with paragraph ( b c )(5)(i) or (ii) of this section, the authorized account representative or alternate authorized account representative, as appropriate, must submit to the Admi nistrator 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 authorizedaccount representati ve 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 ( b 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 auth orized 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 auth orized account representative or alternate authorized representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR **§** 62.16320( b 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 40 CFR **§** Formatted: Font: Bold

Formatted: Font: Bold62.16320( b 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 40
CFR **§** 62.16320(c)(5) is terminated .”. .” (iv) A notice of delegation submitted un der paragraph ( b 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 ( b 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 a lternate authorized account representative of a general account may submit to the Administrator a request to close the account. Such request shall must include a correctly Formatted: Font: Boldsubmitted CO 2 allowance transfer under §62.16330 for any CO 2 allowances in the accoun t to one or more other Allowance Management Tracking and Compliance System accounts. (ii) If a general account has no CO 2 allowance transfers to or from the account for a 12

- month period or longer and does not contain any CO 2 allowances, 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 Admin istrator receives a correctly submitted CO 2 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 Administ rator 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 authori zed account representative and alternate authorized account r epresentative **.** 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, s ubmissions concerning the deduction or transfer of CO 2 allowances in theaccount, 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 CO 2**  **allowances be recorded in compliance**
**accounts?** (a) By June 1, 2021, and by June 1 of each year prior to the beginning of each compliance period thereafter, the Administrator will record in each facility's compliance account the CO 2 allowances allocated to the affected EGUs at the facility in accordance with §62.16240(a), or with a state allowance

distribution methodology approved under subpart UUUU of part 60 of this chapter, for the upcoming compliance period. (b) By Except as specified in par agraph (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 CO 2 allowances to a recipient , other than an allocation described in paragrap hs (a) through (b) of this section, 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 , the Administrator will re cord such allocation in the appropriate Allowance Management System
account . Formatted: Not Superscript/ Subscript(c) When recording the allocation of CO 2 allowances to an affected EGU or other entity in an Allowance Management Tracking and Compliance System account, the Administrator will assign each CO 2 allowance a unique serial number that will include digits identifying the year of the compliance period for which the CO 2 allowance is allocated. (d) By December 1, 2021 and December 1 of each year thereafte r, the Administrator will record in each renewable energy project’s general account, the CO 2 allowances allocated from the renewable energy set

- aside to the project in accordance with §62.16245(a), for the following year. (e) By November 1 of the first yea r of each compliance period beginning in 2025, and each compliance period thereafter, the Administrator will record in each facility's compliance account the CO 2 allowances allocated from the output

- based set

aside to the eligible EGUs at the facility in a ccordance 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 CO**  **2 allowances be submitted?**  (a) An authorized account representative seeking recordation of a CO 2 allowance transfer shall must submit the transfer to the Administrator.(b) A CO 2 allowance transfer shall 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 CO 2 allowance that is in the transferor account and is to be transferred; and (iii) The name and si gnature of the authorized account representative of the transferor account and the date signed; and (2) When the Administrator attempts to record the transfer, the transferor account includes each CO 2 allowance identified by serial number in the transfer. **§62.16335 When will CO**  **2 allowance transfers be recorded?**  (a) Within five 5 business days (except as provided in paragraph (b) of this section) of receiving a CO 2 allowance transfer that is correctly submitted under §62.16330, the Administrator will record a CO 2 allowance transfer by moving each
CO 2 allowance from the transferor account to the transferee account as specified in the transfer. (b) A CO 2 allowance transfer to or from a compliance account that is submitted for recordation after the allowance tra nsfer deadline for a compliance period and that includes anyCO 2 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 CO 2 allowance transfer is not correctly submitted under §62.16330, the Administrator will not record such transfer. (d) Within five 5 business days o f recordation of a
CO 2 allowance transfer under paragraphs (a) and (b) of the section, the Administrator will notify the authorized account representatives of both the transferor and transferee accounts. (e) Within 10 business days of receipt of a CO 2 allo wance 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

- r ecordation. **§62.16340 How will deductions for compliance with a CO**  **2 emission**  **standard occur?** (a) A vailabi lity for deduction for

c ompliance **.** CO 2 allowances are available to be deducted for compliance with a facility's CO 2 emission standard for a compliance period only if the CO 2 allowances: Formatted: Font: Not Bold, Underline(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 CO 2 allowance transfers submitted by the allowance transfer deadline for a compliance period, the Administrator will deduct from each facility's compliance
account CO 2 allowances avai lable under paragraph (a) of this section in order to determine whether the facility meets the
CO 2 emission standard for such compliance period, as follows: (1) Until the amount of CO 2 allowances deducted equals the number of tons of total CO 2 emissions fr om all affected EGUs at the facility for such compliance period; or (2) If there are insufficient CO 2 allowances to complete the deductions in paragraph (b)(1) of this section, until no more
CO 2 allowances available under paragraph (a) of this section

rema in in the compliance account. (c)(1) Identification of CO 2 allowances by serial number **.** The authorized account representative for a facility's compliance account may request that specific CO 2 allowances, identified by serial number, in the compliance accou nt 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 shall 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 f acility and the appropriate serial numbers. (2) First

- in, first

- out **.** The Administrator will deduct
CO 2 allowances under paragraph (b) or (d) of this section from the facility's compliance account in accordance with a complete request under paragraph (c)(1) of this section or, in the absence of such request or in the case of identification of an insufficient amount of CO 2 allowances in such request, on a first

- in, first

- out accounting basis in the following order: (i) Any CO 2 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 CO 2 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) D eductions 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 accoun t an amount of CO 2 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?**  (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 CO 2 mass emissions to be m onitored and reported according to part 75 of this chapter. The owner or operator of an affected EGU must determine the CO 2 mass emissions (tons) for the compliance period as follows: 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 CO 2 mass (tons) according to paragraph (a)(4) or ( a)( 5) of this section, except that a complete data record is required, i.e., CO 2 mass emissions must be reported for each operating hour. Therefore, substitute data values recorded under part 75 of this chapter for CO 2 concentration, stack gas flow rate, stack gas moisturecontent, fuel flow rate and/or GCV shall must be used in the calculations; and (2) Sum all of the hourly CO 2 mass emissions values over the entire compliance period. (3) The owner or operator of an affected EGU must install, calibrate, maintain, and operate a sufficient number of watt meters to continuously measure and record on an hourly basis net electric output. Measurements must be performed using 0.2 accuracy class electricity metering instrumentation and calibration procedures as specified under ANSI Standards No. C12.20. Further, the owner or operator of an affected EGU that is a combined heat and power facility must install, calibrate, maintain and operate equipment to continuously measure and record on an hourly basis useful thermal output and, if applicable, mechanical output, which are used with net electric output to determine net energy output (P net ) . 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 CO 2 mass emissions (lbs) from each affected unit using the procedures in paragraphs (a)(4)(i) through ( vii vi ) of this section, except as otherwise provided in paragraph (a)(5) of this section. Formatted: Not Superscript/ Subscript(i) The owner or operator of an affected EGU must install, certify , operate, maintain, and calibrate a CO 2 continuous emissions monitoring system (CEMS) to directly measure and record CO 2 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 O 2 monitor is used this way, it only quantifies the combustion CO 2 ; therefore, if the EGU is equipped with emission controls that produce non

- combustion CO 2 (e.g., from sorbent injection), then this additi onal CO 2 must be accounted for, in accordance with section 3 of appendix G to part 75 of this chapter. As an alternative to direct measurement of CO 2 concentration, provided that the affected EGU does not use carbon separation (e.g., carbon capture and sto rage), the owner or operator of an affected EGU may use data from a certified oxygen (O 2 ) monitor to calculate hourly average CO 2 concentrations, in accordance with §75.10(a)(3)(iii) of this chapter. If CO 2 concentration is measured on a dry basis, then th e 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 CO 2 mass emission rate (tons/hr), either from Equation F

- 11 in Appendix F to part 75 of this chapter (if CO 2 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 CO 2 concentration is measured on a dry basis). CO 2 mass emissions must be reported for each operating hour. Therefore, substitute data values recorded under part 75 of this chapter for CO 2 concentration, stack gas flow rate, stack gas moisture content, fuel flow rate and/o r GCV shall must be used in the calculations

. (iii) Next, multiply each hourly CO 2 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 CO 2. Multiply the result by 2000 lb/ton to con vert it to lb. (iv) The hourly CO 2 tons/hr values and EGU (or stack) operating times used to calculate CO 2 mass emissions are required to be recorded under §75.57(e) of this chapter and must be reported electronically under §75.64(a)(6), if required by a plan. The owner or operator must use these data, or equivalent data, to calculate the hourly CO 2 mass emissions. (v) Sum all of the hourly CO 2 mass emissions values from 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 CO 2 mass emissions from an affected EGU uses, the monitoring system must meet the applicable certification and quali ty 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)( 3 4 ) of this section, determine the hourly CO 2 mass emissions according to paragraphs (a)(5)(i) through ( a)(5)( 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 hourl y heat input rate, use Equation
G

- 4 in Appendix G to part 75 of this chapter to calculate the hourly CO 2 mass emission rate (tons/hr).(iii) Multiply Determine the hourly tons/hr CO 2 mass emission
rate from (tons/hr) using the procedures specified in parag raph (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 it to it to tons of CO 2 . Then, multiply the result by 2000 lb/ton to convert it to lb. (iv) The hourly CO 2 tons/h r values and EGU (or stack) operating times used to calculate CO 2 mass emissions are required to be recorded under §75.57(e) of this chapter and must be reported electronically under §75.64(a)(6), if required by a plan. You must use these data, or equivale nt data, to calculate the hourly CO 2 mass emissions. (v) Sum all of the hourly CO 2 mass emissions values (lb) from 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 (F c ) using Equation F

- 7b in section 3.3.6 of appendix F to part 75 of this chapter, and may use these F c values in the emissions calculations instead of using the defau lt F c 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 netelectric output. Measure ments 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 oper ator 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)( 3 4 ) or (5 ) of this section to calculate the total CO 2 mass emissions, you must determine P net (the corresponding hourly net energy output in MWh) according to the procedures in paragraphs (a)( 4 6 )(i)(A) and (B) of this section, as appropriate for the type of affected EGU(s). For an operating hour in which a v alid CO 2 mass emissions value is determined according to paragraph (a)( 2 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 CO 2 mass emissions value is determined according to paragraph (a)( 2 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 shall must be counted as zero for this calculation. (A) Calculate P net 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 E GU or stack operating time.

PP

nnnnnn = ( PPPP ) SSSS + ( PPPP ) CC + ( PPPP ) IIII − ( PPPP ) FFFF T DF ( PPPP ) SSSS + ( PPPP ) CC + ( PPPP ) IIII − ( PPPP ) AA TDF + [ ( PPPP ) PP + ( PPPP ) HHHH + ( PPPP ) IIII ] Where: a
P net = 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 equipmentin MWh. (Pe) FW A = Electric energy used to power boiler feedwater pumps at steam generating units 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 E GU. This is calculated using the equation specified in paragraph (a)( 5)(ii 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, electric ity, produce mechanical energy output, or enhance the performance of the affected EGU in MWh.

TDF = Electric Transmission and Distribution Factor of0.95 for a combined heat and power affected EGU where at least on an annual basis 20.0 percent of the tota l 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: ( PPPP ) PP = QQ mm × HH CCCC 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. Q m = Measured steam flow in kilograms (kg) (or pounds (lb)) for the operating hour.

H = Enthalpy of the s team at measured temperature and pressure (relative to SATP conditions or theenergy in the condensate return line, as applicable) in Joules per kilogram (J/kg) (or Btu/lb).
CF = Conversion factor of 3.6 x 10 9 J/MWh or 3.413 x 10 6 Btu/MWh.

(ii) [Reserved ] (7) In accordance with §60.13(g), if two or more affected EGUs implementing the continuous emissions monitoring provisions in paragraph (a)(1) of this section share a common exhaust gas stack and are subject to the same emissions standard, then the

owner or operator may monitor the hourly CO 2 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 o f 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)( 2 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 CO 2 mass emissions andthe “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 appl icable emissions standard by summing the
CO 2 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 CO**  **2 annual allowances for future use or**  **transfer?** (a) A CO 2 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 CO 2 allowance that is held in a compliance account or a general account will remain in such accoun t unless and until the CO 2 allowance is deducted or transferred under
§ § § 62.16240(b), § 62.16335, § 62.16340 , §62.16345 , 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 Management Tracking and Compliance System account. Within 10 business days of making such correction, the Administrator will notify the aut horized 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 ( d 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 CO 2 mass emission rate value (tons/hr) an d unit (or stack) operating time, as monitored and reported according to part 75 of this chapter, for each unit or stack operating hour in the compliance period; (ii) The calculated CO 2 mass emissions (tons) for each unit or stack operating hour in the com pliance period; (iii) The sum of the CO 2 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 (P net ) values for each unit or stack operating hour in the complia nce period; and (v) The sum of the hourly net energy output values for all of the unit or stack operating hours in the compliance period

. ; and ( iii vi ) If the report covers the final quarter or a compliance period , then you must include the CO 2 emission Formatted: Font: Courier Newstandard 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 allowance s , 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 If set

- aside allowances

were us ed from an eligible resource by an affected EGU to comply with its emission standard, then the designated representative must include in their report the eligible resource identification information sufficient to 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 shall must make all submissions required under the
CO 2 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 repor ts required under paragraph (a) of this section using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool provided by the Clean Air Markets Division in the Office of Atmospheric Programs of
EPA. (d) For affected EGUs under this subpart that are not in the Acid Rain Program, you must also meet the reporting requirements and submit reports as required under subpart G of part 75 of this chapter, to the extent that those requirements and reports provide applicable data for the compliance dem onstrations required under this subpart. (e) If your affected EGU captures CO 2 to meet the applicable emission standard, then you must report in accordance with the requirements of 40 CFR Part p art 98 Subpart , s ubpart PP , of this chapter and either: (1) Report in accordance with the requirements of 40 CFR
Part p art 98 , subpart RR , of this chapter , if injection occurs

on - site; or (2) Transfer the captured CO 2 to an EGU or facility that reports in accordance with the requirements of 40 CFR Part p art 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 operat or of each affected EGU must maintain the records, as described in paragraphs (a)(1) through and (2) of this section, for at least 5 years following the date of each compliance period, occurrence, measurement, maintenance, corrective action, report, or record. (1) The owner or operator of an affected EGU must maintain each record on site for at least 2 years after the date of each compliance period, compliance true

- up period, occurrence, measurement, maintenance, corrective action, report, or record, whichever i s 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 CO 2 Mass

- based Trading Program

. ; (iii) Data that is required to be recorded by 40 CFR
Part p art 75 Subpart , s ubpart 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 ( c 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 indep endent verifier verification report associated with the issuance of each specific set aside allowance, and each regulatory approval and any documentation that supports the issuance of each set aside allowance by the Administrator. (B) All records and repor ts 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 Administra**  **tor take on submissions?**  (a) The Administrator may review and conduct independent audits concerning any submission under the CO 2 Mass

- based Trading Program and make appropriate adjustments of the information in the submission. (b) The Administrator may deduct CO 2 allowances from or transfer CO 2 allowances to a compliance account, based on theinformation in a submission, as adjusted under paragraph (a )(1 ) of this section, and record such deductions and transfers. **Definitions §62.16375**  **What definitions a pply to this subpart?**  The terms used in this subpart shall have the meanings set forth in this section as follows: Acid Rain Program means a multi

- state SO 2 and NO X air pollution control and emission reduction program established by the Administrator under title IV of the Clean Air Act and parts 72 through 78 of this chapter. Administrator means the Administrator of the United States Environmental Protection Agency or the Director of the Clean Air Markets Division (or its successor determined by the Ad ministrator) of the United States Environmental Protection Agency, the Administrator's duly authorized representative under 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 a
any steam generating unit, integrated gasification combined cycle ( IGCC ), , or stationary combustion turbine that meets the relevant applicability conditions requirements in section §62.16210
. §§60.5840( b) and 60.5845 of this chapter. An affected EGU is not an eligible resource. Formatted: Space After: 8 pt Formatted: Font color: Black

Formatted: Font color: BlackAllocate or allocation means, with regard to CO 2 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 of this chapter , t o: (1) An affected EGU; (2) A renewable energy set

- aside; (3) An output

- based set

- aside; or (4) An A ny other entity not listed in paragraphs (1) through (3) of this definition; specified by the Administrator

. Allowable CO 2 emission rate means, for an affected EGU, the most stringent State s tate or federal CO 2 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 c overs the longest averaging period not exceeding one year. Allowance Tracking and Compliance System ( ATCS ) means the system by which the Administrator records allocations, deductions, and transfers of CO 2 allowances under the CO 2 Mass

based Trading Program. Such allowances are allocated, recorded, held, deducted, or transferred only as whole allowances. Allowance Management System account means an account in the Allowance Management System established by the Administrator forpurp oses of recording the allocation, holding, transfer, or deduction of CO 2 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 au thorizations 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, m idnight 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 CO 2 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 CO 2 emission standard for such compliance period in accordance with §§62.16220 and 62.16340. Alternate designated representative means, for a CO 2 Mass

base d Trading Program facility and each affected EGU at the facility, the natural person who is authorized by the owners and operators of the facility and all such affected EGUs at the facility, in accordance with this subpart, to act on behalf ofthe designat ed representative in matters pertaining to the CO 2 Mass

- based Trading Program. If the facility is also subject to the Acid Rain Program, TR NO X Annual Trading Program, TR
NO X Ozone Season Trading Program, TR SO 2 Group 1 Trading Program,
or TR SO 2 Group 2 T rading Program, then this natural person shall be the same natural person as the alternate designated representative, as defined in the respective program. nnual 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 CO 2 allowances held in the general account and, for a CO 2 Mass

- based Trading facility's compliance account, the designated representative of the facility 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 a nd convert individual output signals from pollutant concentration monitors, flowmonitors, 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 , bas e 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. [placeholder for biomass] 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 contemporari ly 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 municipa l wastes, including gases and liquids recovered from the decomposition of non

- fossilized and biodegradable organic material).Boiler means an enclosed fossil

- or other

- fuel

- fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or other medium. Business day means a day that does not fall on a weekend or a federal holiday. Capacity factor means, as used for the output based set

aside, the ratio of the net electrical energy produced by a generating unit for the period of time considered to the electrical energy that could have been produced at continuous net summer capacity during the same period. Certifying official means a natural person who is: (1) For a corporation, a president, secretary, treasurer, or vice

- presid ent 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 respectiv ely; or (3) For a local government entity or State s tate , 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 . CO 2 allowance means a limited authorization issued and allocated by the Administrator under this subpart, or by a Stateor permitting authority under a state allowance

- distribution methodology approved by the Administrator under §60.24(x) of this chapter, to emit one ton of CO 2 during a compliance period of the specified calendar year for which the authorization is allocated or of any calendar year thereafter under the CO 2 Mass

Based Trading Program.
CO 2 allowance deduction or deduct CO 2 allowances means the permanent withdrawal of CO 2 allowances by the Administrator from a compliance account ( e.g. , in order to account for compliance with the CO 2 emission standard).
CO 2 allowances held or hold CO 2 allowances means the CO 2 allowances treated as included in an Allowance Management Tracking and Complianc e 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, CO 2 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, CO 2 allowance transfer in accordance with this subpart.
CO 2 emission goal means a statewide rate

- based CO 2 emission goal or mass

- based CO 2 emission goal specified in § 62. 16270 16235
.CO 2 emissions limitation means the tonnage of CO 2 emissions authorized in a compliance period in a given year by the CO 2 allowances available for deduction for the facility under §62.16340(a) for such compliance period.
CO 2 Mass

- Based Trading Program means a multi

- state CO 2 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 p lan or state allowance distribution methodology, or by the Administrator under subpart UUUU of part 60 of this chapter , as a means of controlling CO 2 emissions. Coal means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see §60.17), coal refuse, and petroleum coke. Synthetic fuels derived from coal for the purpose of creating useful heat, including but not limited to solvent

- refined coal, gasified coal (not meeting the definition of natural gas), coal

- oil mixtures, and coal

- water mixtures are included in this definition for the
purp oses of this subpart. Coal

- derived fuel means any fuel (whether in a solid, liquid, or gaseous state) produced by the mechanical, thermal, or chemical processing of coal. Coal means the definition as defined in subpart TTTT ofpart 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 p ower unit or CHP unit, (also known as “cogeneration”) means an electric generating unit that use use s 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. Common practice baseline or ( CPB ) means a baseline derived based on a default technology or condition that would have been in place at the time of implementation of an EE measure in the absence of the EE measure (for example, the standard or market

average or 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 Management Tracking and Compliance System account, established by the Administrator for a CO 2 annual facility under this subpart, in which any CO 2allowance allocations to the affecte d EGUs at the facility are recorded and in which are held any CO 2 allowances available for use for a compliance period in a given year in complying with the facility's CO 2 emission standard in accordance with §§62.16220 and 62.16340. Compliance period mean s 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: (1) Compliance Period 1 means the period of three calendar years fr om January 1 2022 to December 31, 2024. (2) Compliance Period 2 means the period of three calendar years from January 1, 2025 to December 31, 2027. (3) Compliance Period 3 means the period of two 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 un der 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 CO 2 emissions, stack gas volumetric flow rate, stack gas moisture content, and Formatted: Font: 12 ptO 2 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 monito ring 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 chap ter and providing a permanent, continuous record of the stack gas moisture content, in percent
H 2 O; (3) A CO 2 monitoring system, consisting of a CO 2 pollutant concentration monitor (or an O 2 monitor plus suitable mathematical equations from which the CO 2 c oncentration is derived) and an automated data acquisition and handling system and providing a permanent, continuous record of CO 2 emissions, in percent CO 2 ; and (4) An O 2 monitoring system, consisting of an
O 2 concentration monitor and an automated data acquisition and handling system and providing a permanent, continuous record of
O 2 , in percent O 2 . Control area opera tor means an electric system or systems, bounded by interconnection metering and telemetry, capable of Formatted: Font: 12 pt
Formatted: Font: 12 pt

Formatted: Font: 12 ptcontrolling generation to maintain i ts interchange schedule with other control areas and contributing to frequency regulation of the interconnection. Deemed savings means estimates of average annual electricity savings for a single unit of an installed demand

side EE measure that : (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 e ner gy e fficiency 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 a system or equipment Formatted: Font: Courier New, 12 ptmodification or to discounting a portion of a generating units capacity for planning purposes. Designated representative means, for a CO 2 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 CO 2 Mass

- based Trading Program. If the CO 2 Mass

- based Trading facility is also subject to the Acid Rain Program, TR NO X Annual Trading Program,
TR NO X Ozone Season Trading Program, TR SO 2 Group 1 Trading Program, or TR SO 2 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 fuel oils that comply with the specifications for fuel oil numbers 1 and 2, as defined by the American Society of Testing and Materials in ASTM D396 (incorporated by reference, see §60.17); diesel fuel oil numbers 1 and 2, as defined by the American Society for Testing and Materials in ASTM D975 (incorporated by reference, see §60.17); kerosene, as defined by the American Society of Testing and Formatted: Font: 12 pt
Formatted: Font: 12 pt Formatted: Font: 12 pt Formatted: Font: 12 ptMaterials in ASTM D3699 (incorporated by reference, see §60.17); biodiesel as de fined by the American Society of Testing and Materials in ASTM D6751 (incorporated by reference, see §60.17); or biodiesel blends as defined by the American Society of Testing and Materials in ASTM D7467 (incorporated by reference, see §60.17). Distillate oil means the definition as defined in subpart TTTT of part 60 of this chapter

. E nergy e fficiency program or EE program means o rganized 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 e fficiency 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 e fficiency m easure 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.Effective useful life or ( 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. Eligibile Eligible resource means a resource that meets the requirements of § 62.16245 a nd has been registered with the EPA

administered ATCS or an allowance tracking system approved in a State plan by the EPA. An eligible resource is not an affected
EGU
. EM&V plan means a a n 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 , as ; emissions must be measured, recorded, and reported to the Administrator by the designated representative, and as modified by the Administrator: (1) In accordance with this subpart; and (2) With regard to a period before the affected EGU or facility affected EGU is required to measure, record, and report

su ch air pollutants in accordance with this subpart, in accordance with part 75 of this chapter. Formatted: Font: Not Italic

Formatted: Font: Bold

Formatted: Font color: Black
Formatted: Font color: Black

Formatted: Font color: BlackEligible resource Emission r ate c redit ( ERC ) means a

resource tradable compliance instrument that meets the requirements of § 62.16245 and has been registered with the EPA

administered ATCS 60.5790(c) of this chapter. Energy service company means a private enterprises engaged in delivering electricity savings directly for an end

- use

cus t omer or an allowance tracking system approved in a state plan by the EPA. An eligible resource is not as an affected
EGU. 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 allowance s 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 CO 2 emissions limitation for the facility for such compliance period. Existing state program, requirement, or measure means, in the context of a state S tate 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 Formatted: Font: Not Italic Formatted: Font color: Text 1 Formatted: Font color: Text 1or expanded in the future, i n accordance with established plans. An existing state program, requirement, or measure may have past, current, and future impacts on EGU CO 2 emissions. Facility means all buildings, structures, or installations located in one or more contiguous or adjacen t 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 an y 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 two calendar years (with a calendar year beginning o n January 1 and ending on December 31). Final Compliance Period c ompliance p eriod means a compliance period within the final period, each being two 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.
Foss il fuel means natural gas, petroleum, coal, and any form of solid, liquid, or gaseous fuel derived from such material for the purpose definition as defined in subpart TTTT of part 60 of creating useful heat this chapter

.Fossil

- fuel

- fired means, with regard to an affected EGU, combusting any amount of fossil fuel in $$$YYYY or any calendar year thereafter

. Gaseous fuel means any fuel that is present as a gas at ISO conditions and includes, but is not limited to, natural gas, refinery fuel gas, process gas, coke

- oven gas, synthetic gas, and gasified coal. the definition as defined in subpart TTTT of part 60 of this chapter

. General account means an Allowance Management 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 t he 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.
Genera tor 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 ortreatment 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 measured, recorded, and reported to the Administrator by the designated representative and as modified by the Administrator in accordance with this subpart and excluding t he 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), d ivided 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 gas es and generate useful output. Heat recovery steam generating units can be usedwith or without duct burners. Indian country means “Indian country” as defined in 18 U.S.C. 1151. Integrated gasification combined cycle facility or IGCC facility means a combined cycle facility that is designed to burn fuels containing 50 percent (by heat input) or more solid

derived fuel not meeting the definition of natural gas plus any integrated equipment that provides electricity or useful thermal output to either the affected facility or auxiliary equipment. The Administrator may waive the 50 percent solid

- derived fuel requirement during periods of the gasification system construction, startup and commissioning, shutdown, or repair. No solid fuel is directly burned in the unit during operation. Interim period means the period of eight calendar years from January 1, 2022 to December 31, 2029. The interim period is comprised of three compliance periods, compliance period 1, compliance period 2, and compliance period 3

.. . ISO conditions means 288 Kelvin (15 o C), 60 percent relative humidity and 101.3 kilopascals pressure. Liquid fuel means any fuel that is present the definition as a liquid at ISO conditions and includes, but is not limited to, distillate oil and residual o il. defined in subpart TTTT of part 60 of this chapter

.M&V report means a monitoring and verification report that meets the requirements of § 62.16265. Maximum design heat input means, for an affected EGU, the maximum amount of fuel per hour (in Btu/hr) that the affected EGU is capable of combusting on a steady state basis as of the initial installation of the affected EGU as specified by the manufacturer of the affected EGU. Mechanical output means the useful mechanical energy that is not used to operate the affected facility, generate electricity and/or thermal output, or to enhance the performance of the affected facility. Mechanical energy measured in horsepower hour should be converted into MWh by multiplying it by 745.7 then dividing by 1,000,000.
Mo nitoring 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 rest ricted by seasonal or other deratings) as of such installation as specified by the manufacturer of the generator or, starting from the completion Formatted: Font: Courier New, 12 ptof any subsequent physical change in the generator resulting in an increase in the maximum electrical generati ng 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 a fluid mixture of hydrocarbons (e.g., methane, ethane, or propane), composed of at least 70 percent methane by volume or that has a gross calorific value between 35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic foot), that maintains a gaseous state under ISO conditions. In addition, natural gas contains 20.0 grains or less of total sulfur per 100 standard cubic feet. Finally, n atural gas does not include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coal

- derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable s ulfur content or heating value. Natural gas the definition as defined in subpart TTTT of part 60 of this chapter

. Net

- electric output means the amount of gross generation the generator(s) produce (including, but not limited to, output from steam turbine(s) , combustion turbine(s), and gasexpander(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 electr icity 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
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 op erate 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 o f 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 ). (2) For combined heat and power facilities where at least 20.0 percent of the total gross or net energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross or net energy output consists of useful thermal output on a 12

- operating month rolling average basis, the net electric or mechanical output from the affected EGU divided by 0 .95, plus 100 percent of the useful thermal output; (e.g., steam delivered to an industrial process for a heating application).
Net Summer Capacity s ummer c apacity 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 oper ation means, with regard to an affected EGU, to combust fuel.Operator means, for a CO 2 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 affec ted EGU and shall include include s , but is
not be limited to, any holding company, utility system, or plant manager of such facility or affected EGU.
Owner means, for a CO 2 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 in terest in an affected EGU at the facility or the affected EGU, provided that, unless expressly provided for in a leasehold agreement, “owner” shall does not include a passive lessor, or a person who has an equitable interest through such lessor, whose renta l payments are not based (either directly or indirectly) on the revenues or income from such affected EGU; and ( 3) Any purchaser of power from a a n 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 that the affected EGU's owners an d operators do not expect to return toservice in the future for which the affected EGU's owners and operators (1) have taken on as enforceable obligation s 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

. Permitting authority means “permitting a uthority” as defined in §§70.2 and 71.2 of this chapter. Petroleum means crude oil or a fuel derived from crude oil, including, but not limited to, distillate and residual oil. Qualifying Qualif ied biomass means a biomass feedstock that is demonstrated to qualify as a method to control increases of
CO 2 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 elec tricity use due to unaccounted

- for factors that affect electricity use. The magnitude of random error can be quantified based on the variations observed across different units. Receive or receipt of means, when referring to the Administrator, to come into possession of a document, information, or correspondence (whether sent in hard copy or by authorized electronic transmission), as indicated in an officiallog, or by a notation made on the document, information, or correspondence, by the Administrator in t he regular course of business. Recordation , record , or recorded means, with regard to CO 2 allowances, the moving of CO 2 allowances by the Administrator into, out of, or between Allowance Management Tracking and Compliance System accounts, for purposes of al location, transfer, or deduction. Reference method means any direct test method of sampling and analyzing for an air pollutant as specified in §75.22 of this chapter. Replacement , replace , or replaced means, with regard to an affected EGU, the demolishing of an affected EGU, or the permanent retirement and permanent disabling of an affected EGU, and the construction of another affected EGU (the replacement affected EGU) to be used instead of the demolished or retired affected EGU (the replaced affected EGU)

. Solid fuel means any fuel that has a definite shape and volume, has no tendency to flow or disperse under moderate stress, and is not liquid or gaseous at ISO conditions. This includes, but is not limited to, coal, biomass, and pulverized solid fuels.
S olid waste incineration unit means a stationary, fossil

fuel

- fired boiler or stationary, fossil

- fuel

- fired combustionturbine that is a “solid waste incineration unit” as defined in section 129(g)(1) of the Clean Air Act. Systematic error means inaccuracie s 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 tempera ture and pressure (SATP) conditions means 298.15 Kelvin (25 o C, 77 o F)) and 100.0 kilopascals (14.504 psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is 50 Btu/lb. State agent means an entity acting on behalf of the
state S tate , with the legal authority of the state S tate . State measures means measures that the state S tate 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 S tate plan. Stationary combustion turbine means all equipment, including but n ot 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 an cillary components and sub

components comprising any simple cycle stationary combustionturbine, 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 mounte d on a vehicle for portability. If a stationary combustion turbine burns any solid fuel directly Stationary combustion turbine means all equipment, including but not limited to the turbine engine, the fuel, air, lubrication and exhaust gas systems, control systems (except emissions control equipment), heat recovery system, fuel compressor, heater, and/or pump, post

- combustion emissions control technology, and any ancillary components and sub

- components comprising any simple cycle stationary combustion turbin e, 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 e quipment. 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 direct ly then it is considered a steamgenerating 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 equi pment. 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 trans mission 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 theelectrical 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 combus ts 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 a n 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 conditio ns.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. Utilit y 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, o perated, and maintained according to part 75 of this chapter. For CEMS, the initial certification requirements in §75.20 of this chapter and appendix A to part 75 of this chapter must be met before quality

- assured data are reported under this subpart; for on going quality assurance, the daily, quarterly, and semiannual/annual test requirements in sections 2.1, 2.2, and 2.3 of appendix B to part 75 of this chapter must be met and the data validation criteria in sections 2.1.5, 2.2.3, and 2.3.2 of appendix B to part 75 of this chapter apply. For fuel flow meters, the initial certification requirements in section 2.1.5 of appendix D to part 75 of this chapter must be met before quality

- assured data are reported under this subpart (except for qualifying commerci al 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 repor t that meets the requirements of § 62.16270.
Waste

- to

- Energy or WTE means a process or unit (e.g., solid waste incineration unit) that burns recovers energy from the biogenic fraction conversion or combustion of waste stream materials, such as municipal solid waste (which is considered a qualifying biomass feedstock) , to generate electricity and/ or heat

. **§62.16380 Measurements, abbreviations, and acronyms.** The measurements, abbreviations, and acronyms used in this subpart are defined as follows:
ADR

- alte rnated designated representative
Btu

— British thermal unit
CO 2 — 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 Formatted: Space After: 8 pt Formatted: Font: Courier New, 12 pt

Formatted: Font: ItalicH 2 O

— water hr

— hour
IGCC

- i ntegrated gasification combined cycle kg

- kilogram kW

— kilowatt electrical kWh

— kilowatt hour lb

— pound
M&V

– – measurement and verification
mmBtu

—mill ion Btu
MWe

— megawatt electrical MWh

— megawatt hour
O 2 — oxygen
PB

- MV

- project

- based measurement and verification
PSD

- prevention of significant deterioration
T&D

- transmission and distribution
TRM

- technical reference manual
mmBtu

—million Btu
MWe

— megawatt electrical MWh

— megawatt hour
O 2 — oxygen
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**  Formatted: Font color: Auto

Formatted: Font color: Black**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 CO 2 Rate

- based Trading Program? 62.16430 What are the administrative appeal procedures? 62.16431 How will the Clean Energy Incentive Program be administered under the federal plan ? **Emission Rate Credit Issuance, Adjustment and Revocation**  62.16434 What affected EGUs qualify for generation of ERCs? 62.16435 What eligible resources qualify for generation of ERCs in addition to affected EGUs? 62.16440 What is the process for revocation of qualification status of an eligible resource? 62.16445 What is the process for the issuance of ERCs? 62.16450 What is the process for error adjustments or misstatement, and suspension of ERC issuance? **Evaluation Measurement and Verificatio n 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 el igible 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 in terest?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 alte rnate 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 representati on? 62.16505 What is the Administrator’s role in objections concerning designated representatives and alternate designated representatives? 62.16510 What process must designated representatives and alternate designated representatives follow to delegate their authority? **Monitoring, Recordkeeping, Reporting** 62. 16515 How are compliance accounts and general accounts established and used, and how is ERC issuance documentation accessed ? 62.16525 How must transfers of ERCs be submitted? 62.16530 When will ERC transfers be recorded? 62.16535 How will deductions for compliance with a CO 2 emission standard occur? 62.16540 What monitoring requirements must I comply with? 62.16545 May I bank CO 2 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** 6 2.16570 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

— CO 2 Emission Standards (Pounds of CO 2 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 general, designated representative, crediting, and monitoring provisions requirements for the Clean Power Plan (CPP) CO 2 Rate

- based Trading Program, under section 111 of the Clean Air Act and subpart UUUU of
Part p art 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 s ubpart are greenhouse gases. The greenhouse gas limitations in this subpart are in the form of an emission s tandard for carbon dioxide (CO2). (c) PSD and Title V T hresholds for G reenhouse G ases. (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 stateimplementation 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 th e 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 o f the Act” shall be considered to be the pollutant 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 S tate that has incorporated by reference this subpart as a state S tate plan, or portion of a state S tate 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 S tate under part 62 of this c hapter. (b) An affected EGU is any steam generating unit, Integrated Gasification Combined Cycle ( 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 pursuant to an enforceable title V operating permit condition shall be as defined in § 62.16570 is exempt from § § § 62.16420(c)(1 )[ ) [ CO 2 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 shall 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 submita statement to the Administrator. The statement shall 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 shall must not emit any CO 2 , starting on the date that the exemption takes effect. (2) For a period of five years from the date the records are created, the owners and operators of an affected EGU exempt under paragraph (a) of this section shall must retain, at the affected EGU, records demonstrating that the affected EGU is permanently retired. The five 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 un der paragraph (a) of this section shall must comply with the requirements of the CO 2 Rate

- based Trading Program concerning all accruing during a ny compliance periods for which the exemption is not in effect, even if such requirements arise, or must be complied with , after the exemption takes effect. **General Requirements** Formatted: Underline

Formatted: Font: Courier New**§62.16420 What**  **emission standards and requirements must I comply**  **with?** (a) Designated representative requirements. The owners and operators shall comply with the requirement to 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

r epresentative, of affected EGU shall 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 shall must be used to calculate CO 2 emissions under §62.16208(a)(2) and (b) and to determine compliance with the CO 2 emission standard under paragraph (c) of this section, provided that, for each monitoring location from which emissions are reported, the emissions emission rate used in determining compliance shall must be the CO 2 emission rate at the monitoring location determined in accordance with paragraph (c) of this section. (c) CO 2 emission standard requirements

. (1) CO 2 emission standards. Each designated representative for each affected EGUmust demonstrate compliance with its emission standard listed in Table 1 of this subpart, as applicable, by calculating a CO 2 emission rate by factoring stack emissions and any emission rate credits (ERCs) into the foll owing equation:

CCCC 2 eeeeeeeeeeeeee rrrr = ∑ MM CCCC 2 ∑ MMMM h oooo + ∑ MMMM h
Where:
CO 2 emission rate = An affected EGUs calculated CO 2 emission rate that will be used to determine compliance with the applicable CO 2 emission standard.

M CO2 = Measured CO 2 mass in units of pounds (lbs) summed over the compliance period for an affected EGU. MWh op = Total net energy output over the compliance period for an affected EGU in units of MWh. MWh ERC = 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 H as a unique serial number; Formatted: Font: Courier New(ii) represents R epresents one whole MWh of actual energy generated or saved with zero associated carbon dioxide emissions; (iii) was W as issued to an eligible resource that meets the requirements of § 62.16435 or to an affected EGU t hat meets the requirements of §62.16434, by the Administrator through an ERC tracking system or the Allowance Tracking and Compliance System; and (iv) was W as 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 S tate 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 affe cted 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 st andard during a compliance period, then: (i) The owners and operators of the affected EGU shall must hold ERCs required for deduction under §62.16535( d); and 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 CAA Clean Air Act , and the United States, states S tates , 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 c orrective actions, and shall 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 shall 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 theClean Air Act, 42 U.S.C. § 7604, and the United States, states, and other persons have the ability to enforce violations and secure corrective actions; and (iv) If an affected EGU obtained sufficient facially valid ERCs to meet its emission standard, but those ERCs were found to be invalid, then it may be subject to federal enforcement as specified in (c)(5) (iii) of this section

. (d) Compliance periods. (1) An affected EGU shall 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. ( 2 1 ) Vintage of ERCs held for compliance. An ERC held for
comp liance 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. ( 3 2 ) Allowance Tracking and Compliance System (ATCS) . Each
ERC shall must be held in, deducted from, transferred into, out of, or between ATCS accounts in accordance with this subpart. ( 4 3 ) Limited authorization. (i) An ERC shall only be used in accordance with the CO 2 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 theAdministrator determines is necessary or appropriate to implement any provision of t he Clean Air Act. ( 5 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 shall will be required for any crediting, holding, deduction, or transfer of ERCs in accordance with this subpart, provided that the requirements applicable to such creditings, holdings, deductions, or transfers of ERCs are already incorporated in such permit

.(f) L iability. Any provision of the CO 2 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 CO 2 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 applic able, approved
State s tate implementation plan, a federally enforceable permit,

or any other requirement of the Clean Air Act. **§ 62.16425 How should I compute time under the CO**  **2 Rate**  **- based**  **Trading Program?** (a) Unless otherwise stated, any time period scheduled, under the CO 2 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 CO 2 Rate

- Based Trading Program, to begin b efore the occurrence of an act or event shall 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 CO 2 Rate

- Based Trading Program, is not abusiness day, then the time period shall 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 CO 2 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 Admi nistrator will award, on behalf of each such state, early action emission rate credits (ERCs) for generation and savings achieved in 2020 and 2021 that result from the following types of renewable energy and demand

- side energy efficiency ( EE ) projects impl emented in or benefitting the state following September 6, 2018 : (1) Metered wind power; (2) Metered solar power; and (3) Demand

- side EE implemented in a low

- income communit y . (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 theaggregate emission performance of affected EGUs required to meet
rate

- based emission standards during the compliance periods. (c) The Administrator wil l 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 CO 2 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 sectio n 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 achie ved, the project will receive two early action ERCs under paragraph (b) of this section and two matching ERCs from the match under paragraph (c) of this section

. **Emission Rate Credit Issuance, Adjustment and Revocation §**  **62.16434 What affected EGUs qualify for generation of ERCs**  ? (a) ERCs may only be issued to affected EGUs under the conditions listed in paragraph (b). paragraph s (b) and (c ) ofthis section

. (b) For a ffected EGUs that emit below their applicable emission standard . The , t he amount of ERCs generated must be calculated using the following equation

. : (1) To calculate the number of ERCs:
ERCs = ( EGU emission standard

− EGU emission rate ) EGU emission standard ∗ EGU generation
Where:
ERCs = N umber of emission rate credits generated by an affected EGU during an applicable compliance period (MWh)

. EGU emission standard = The e mission 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 CO 2 emissions emission rate measured in accordance with § 62.16540 (lb/MWh ) )
. EGU generation = the total T otal net energy output generation of the affected EGU during the applicable compliance period measured in accordance with 62.1654 0 (MWh ) )
. (c) Stationary combustion turbines that meet the definition of an affected EGU may generate net energy output MWh gas shift
ERCs (GS

- ERCs) according to the following equations for allhours of operation during a given compliance period : according to paragraphs (c)(1) through (3) of this section

. (1) To calculate the number of GS

- ERCs: GS

− ERCs = EGU Generation ∗ Incremental Generation Factor ∗ GS

− ERC Emission Factor Where: (1) To calculate the number of GS

- ERCs: GS

- ERCs= EGU Generation * I ncremental Generation Factor*GS

- ERC Emission Factor Where:
GS

- ERC = N et energy output MWh gas shift ERCs

. EGU generation = the total T otal 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 for the applicable factor for the ERC generation each compliance period

. GS

- ER C Emission Factor Rate = value V alue 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: Formatted: Font: Courier NewGS

- ERC Emission Factor = Factor to be used in the equation in paragraph (c)(1) of this section for GS

- ERC calculation

. EGU emission rate = the affected A ffected EGU’s measured CO 2 emissions emission rate measured in accordance with § 62.16540 (lb/MWh ) )
. Steam turbine emission standard = the steam S team turbine emission standard for the corresponding compliance period as found in Table 1 (lb/MWh)

. (3) Notwithstanding any other provision of this subpart,
GS

- ERCs must not be used for compliance by an affected EGU that is a stationary combustion turbine. Stationary combustion turbines may use other ERCs in their compliance demonstration. **§ 62.16435 What eligible resources qualify for generation of ER**  **Cs 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 sola r 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 th e 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 ERCs. (2) The resource must be connected to, and delivers en ergy to or saves electricity, on the electric grid in the contiguous United States. (3) The resource is located in a state S tate whose affected EGUs are subject to rate

- based emission standards pursuant to this regulation, unless the resource is located in a state S tate with mass

- based emission standards and the resource can demonstrate (e.g., through a power purchase agreement or contract for delivery) transmission of its generation into astate S tate whose affected EGUs are subject to rate

- based emission st andards 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) Qualifying Qualif ied biomass; (iii) Waste

- to

- energy , (biogenic portion); (iv) Nuclear energy , or ; (v) A non

- affected combined heat and power unit, including waste heat power ; or (vi) A d emand

- side energy efficiency 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. Note to paragraph (a). All categories of resources other than on - shore utility scale wind, utilit y scale solar photovoltaics (pv), 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. (b) Any resource that does not meet the requirem ents of Formatted: Highlightthis 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 p art 60 of this Part 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 CO 2 emissions outside the electric power sector, including GHG offset projects representi ng emission reductions that occur in the forestry and agriculture sectors, direct air capture, and crediting of CO 2 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 S tate plan. **§ §**  **§ 62.16440**  **Revocation What is the process for revocation**  **of qualification status of an eligible resource** 

. **?** (a) If an eligible resource is found to not meet the requirements of § 62.16435 in the Rate

- based trading
program, T rading P rogram , then the Administrator will revoke the eligibility of the eligible resource to be issued ERCs. Inaddition, 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 f urther eligibility to be issued ERCs. In addition, the provisions of § 62.16450 (a) through (d) may apply. **§ §**  **§ 62.16445**  **What is the process for the issuance of ERCs**  ? The process and requirements for issuance of ERCs for affected EGUs and Eligible e ligible 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 following 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

- mai l 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 electric generating eligible resource, the physical location of the electric generating eligible resource; contact information for the owner or operator of the electric generating eligible resource, if different from the designated representative or authorized account representative; e ligible

resource generator prime mover and /or technology type; generator eligible resource nameplate capacity; generator eligible

resource category (e.g., wholesale generator, wholesale generator also serving onsite customer load, customer

- sited distributed generator ) (if applicable ) ; facility and generating unit IDs (EIA ORIS Code, Facility Registration System (FRS) Code, if applicable); for generators eligible resource , the control area, balancing authority, ISO conditions as defined in§ 62.16570 , or RTO the regional transmission organization in which the generator is located ; (if applicable)

. (A) For an electric generating eligible resource with a nameplate capacity of 1 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 energy efficiency 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 insta llations where the energy

- saving measures are implemented or will be implemented; the parties implementing the energy

- saving project, including lead contractor(s), subcontractors, and consulting firms (if different from the authorized account representativ e); energy

- saving measures installed and/or energy

- savings practices implemented (or to beinstalled/implemented); specifications of equipment and materials installed, or to be installed, as part of the energy

saving project; project plans and technical sc hematics, as applicable ; . (iii) For an energy

- savings resource that involves an EE requirement or program, a description of the energy efficiency

or electricity savings program, including: overall approach or “logic” to the requirement or program, includ ing 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(ie s), or installations where energy

- saving requirements or programs were implemented or will be implemented; electricity consuming system(s), end

- use(s), building or facility type(s), or installations where the energy

- saving requirements or programs are impl emented 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 energy

- savi ng equipment and/or energy

- savings practices implemented (or to be installed/implemented) under the requirement or program; the delivery mechanisms of the requirement or program, which may include financial incentivesor equipment rebates, dissemination of actionable information to electricity customers, on

- site audits paired with technical recommendations ; . (iv) For other electricity

- saving resources (e.g., DSM measures, T&D efficiency improvements transmission and other 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 su ch 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 electr icity

- saving resources were implemented or will be implemented; electricity consuming, transmitting, or distributing system(s), building or facility type(s), or end

- use(s) where the electricity

- saving resource are implemented or will be implemented; the pa rties implementing the electricity

- saving resource, including lead contractor(s), subcontractor(s), and consulting firms (if different from the authorized account representative); specifications of installed equipment and/or implemented practices (or to be installed/implemented); the delivery mechanisms used to implement and propagate the electricity

-saving resource, as applicable ; . (v) For eligible resources with distributed locations, such as measures at multiple residential, commercial, or industrial bui ldings, at a minimum, aggregated information about the location of measures that constitute an eligible resource, provided that the accredited independent verifier and the Administrator have the ability to access information specifying the location of each discrete measure that constitutes an eligible resource. (3) Demonstration that the eligible resource meets all applicable eligibility requirements in § 62.1435. (4) A certification that the eligibility application has only been submitted to the Administrator or pursuant to an EPA

approved multi

- state approach where states S tates are providing for joint issuance of ERCs pursuant to the authority in their individual state S tate 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. ( 8 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 andthe EM&V pla n have been implemented as described in the eligibility application. ( 7 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 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 submitti ng falsestatements and information or omitting required statements and information, including the possibility of fine or imprisonment

. (8 ) 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 registe r the affected EGU or eligible resource in an ERC tracking system that meets the requirements of § 62.16515. Once so registered, the affected EGU or eligible resource is eligible to be issued ERCs, provided all other applicable requirements continue to be m et. (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 repre sentative 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 Formatted: Indent: First line: 0.5"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**  **Adjustments What is the process**  **for error adjustments**  **or misstatement, and**  **suspension of ERC issuance .**  **?** (a) In the event of error or misstatement of quantified MWh of electricity generation or savings in a previous M&V report for which ERCs have been issued, the Administrator may adjust the number of ERCs issued in a subsequent reporting period to address th e 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 Formatted: Font: Courier Newthe 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 shall must submit to the Administrator within 30 days a number of ERCs necessary to correct the error or misstatement. Failur e to meet this requirement will result in prohibition of the authorized account representative for the eligible resource from further participation in the program, unless reauthorized at the discretion of the Administrator. (c) The Administrator may freeze the general account held by a a n 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 a a n 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 fo r 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 ( i d) ( 1 ) th rough ( iii). 3 ) of this section

.( i 1 ) Freeze the general account of for the authorized account representative Eligible e ligible resource, preventing any transfers of ERCs out of the account. ( ii 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. ( iii 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 shall must submit to the Administrator within 3 0 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 ( i e) ( 1 ) through ( iii) 3 ) of this section. ( i 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.( ii 2 ) In the case of repeated error or misstatements in submitted M&V reports. ( iii 3 ) In the case of an intentional misrepresentation in a submitted M&V report. **Evaluation Measurement and Verification Plans, Monitoring and Verification Reports, and Verification**  **§ 62.16455 What are the requirements for evaluation measurement**  **and verification plans for eligi ble resources?**  (a) (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 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 Formatted: Font: Italic10 kW for which metered data are available, each EM&V plan must specify that the requirements in paragraphs (c)( 1)(i) through ( v) be v i ) of this section are met. (i) The generation data is physically measured on a continuous basis using a revenue

- quality meter, which shall

mean mean s a meter used by a control area operator for financial settlements, or a meter that me ets 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 t his 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 genera ting 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 characterist ics , ; (B) All of the generating units are located in the same state, S tate ; (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 sp ecific state S tate 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 ar ea 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 p ursuant to the relevant state S tate plan from the ability to transfer or retire ERCs issued to that qualifying renewable energygenerating resource or, if the generating unit is less than 10 kw and does not generate enough electricity to enable monthly
repo rting, 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 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 wit h on

- site loads other than station service drawing generation before the metering point, ERCs may be issued for on

site load, if the owner or operator of the eligible resource can demonstrate that the metering used is capable of distinguishing between on

- s ite load and station service. (vi) Any other requirements approved by the EPA in connection with the specific state S tate 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 ( v) v i i ) of this section are met.(i) Metered data are unavailable. (ii) At least 1 MW of net energy output is generated to the distr ibution 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 S tate ; (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 a lternative requirements approved by the EPA in connection with the specific state S tate 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. (i v) 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 reso urce), or engineering information that takes into account the capacity, age, and type of qualifying energygenerating resource, and all input parameters and assumptions must be clearly delineated, or if the generating unit does not generate enough electric ity 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. (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 generatio n used on

- site by the customer. (vi) Any other requirements approved by the EPA in connection with the specific state S tate plan pursuant to which that EM&V plan is submitted. (3) For qualifying qualif ied biomass feedstocks used, in addition to the requirem ents 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 Administrator EPA for that biomass feedstock and its associated biogenic CO 2 in connection with that state plan 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 planmust specify: (i) T he total net energy generation from the resource in MWh; (ii) T he 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) T he net energy output is measured with the relevant method approved by the EPA in connection with the specific S tate plan pursuant to which that EM&V plan is submitted demonstrate that the requirements approved by the EPA in connection with that S tate 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 specify: 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) 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 stateplan 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 s ection, each EM&V plan must meet one of the requirements paragraphs (c)(5)(i) through (iii), as applicable, and any other requirements approved by the EPA in connection with the specific state plan pursuant. (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 (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 CO 2 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 emission unit CO 2 emission monitoring and reporting methodologyin 40 CFR 75 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 premises

level 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 or , EE project , or EE

measure must specify how each of the following requirem ents in paragraphs (c)(7)(i) through (x) of this section will be met in quantifying the electricity savings from that EE program or , EE project : , or EE measure . (i) All electricity savings must be quantified on an ex

-post basis, which means after the electricity savings have occurred, or on a real

- time basis, which means simultaneous to at the time the electricity savings

. are occurring. Electricity savings must n ot be quantified on an ex

- ante basis, which means based on projections estimates of electricity MWh savings that have are generated prior to implementing the subject EE program, EE project, or EE measure , and that are not yet occurred but are anticipated to o ccur 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

APMP program, EE project, or EE measure covered in the E E M &V plan, and an explanation of why that particular protocol or guideline was selected. Protocols and g uidelines are considered to be best practice if they: (A) Have gone through a rigorous and credible peer review
process , or that shows the applicable methods to be valid through empirical testing ; and (B) Are widely Have been accepted as best practices and approved for use within the energy efficiency industry by identifiable state regulatory commissions

. Examples of Formatted: Indent: Left: 0", First line: 0.5"such protocols and guidelines are that may be provided in the 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 wo uld 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 common practice baseline CPB was selected for that EE program or project, , 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 . CPBs must be , based on : (A) Characteristics of the EE program or , EE project, or EE

measure ; (B) The delivery mechanism used to implement the EE program

or , EE project , or EE measure (e.g., installed as part of a utility EE program direct install EE program versus a point

- of

sale rebate ), ) ; (C) Local consumer and market characteristics , ;(D) Applicable building en ergy 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. Examples of CPB definitions for specific EE programs and projects are pr ovided in the EM&V guidance issued by the Administrator. (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 approache s 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 Formatted: Indent: First line: 0.5"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 a broad range of th e public, stakeholders, and experts is provided are invited

– with adequate advance notification (via the internet and other social media ), has )

– to provide comment, have at least three 2 months
to respond and 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 q uantifying savings, and must be subsequently updated in the same manner at least every three years. The TRM must indicate, for each subject EE technology or measure, the associated electricity savings value, the conditions under which the value can be appl ied (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 equipment or

measure . (v) All EE program s and , EE projects , or EE measures mustbe quantified at appropriate time intervals (in years) for ensuring sufficient to ensure that MWh savings are accurately and reliably quantified , and such . Such time intervals must be specified and explained in the EM&V plan. Factors that must be taken into consideration when determining th e appropriate time interval include the characteristics of the specific EE program

or , EE project , or EE measure , expected variability in electricity savings (where greater variability necessitates more frequent quantification), the expected scale and magn itude of the electricity savings (where greater quantities of savings necessitate more frequent quantification), and the experience of EE providers implementing and of EE evaluators quantifying a particular program or project type 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 or , EE project , or EE

measur e , and must last no longer than: (A) Every four year intervals for building energy codes and product standards

. ; (B) Every one, two or three years for public or consumer

funded EE program or , EE project, or EE measure , as relevant for the type of EE program or , EE project , or EE measure and factors listed in § 62.16455( paragraph (c) ( 7)( v) above. of this section ;and (C) Annually for commercial and industrial projects, unless the EE resource provider can provide a reasonable justification in the EM& V plan for why this an annual time interval is not feasible , and can additionally explain how the accuracy and reliability of savings values will not be lessened. ( vi) The following factors and their impact on the EM&V plans must specify and document how th e 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 from the specific EE program or project that is the subject of the specific EM&V plan must be addressed in the EM&V plan:

. (A) The effects of any changes in independent variables that will affect the factors on reported electricity savings must be described ( i.e., factors that are not directly related to the EE measure, such as weather, occupancy, and /or 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 an evaluation the application of the EE measure EM&V methods , an industry best

- practice persistence study, deemed estimates of effective useful life, or a combination of all of these three

.( 1 ) If deemed estimates of effective useful life are used, then they must specify the date by which the EE measure will have stopped stop saving electricity is specified

. ( 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) No dou ble counting of the electricity savings may occur, and the EM&V plan must include documentation of the steps taken to avoid double counting. The EM&V plan may specify that the following procedures will be taken to avoid counting the same MWh savings more t han one time: (i (C) The potential sources of double counting, and the associated steps for avoiding and correcting for it, such as: ( 1 ) For programs and projects an EE program or EE project with identified participants, track the type and number of EE measures implemented at the utility

- customer level. ( ii 2 ) For programs an EE program or EE project without identified utility customers participants , such as point

- of

- sale rebates and retailer or manufacturer incentive programs, track applicable vendor, retailer, and manufacturer data. ( iii) Correct for double counting that may occur across 3 )
For EE program s with identified participants (such as those implemented by a utility) and individual EE projects ( outside of EE programs), such as those implemented by an energy service Formatted: Font: Italic Formatted: Font: Italic Formatted: Font: Italic

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Formatted: Font: Italiccompany (ESCO). ) that both have identified participants, use tracking data to avoid and correct for double counting that may occur across the two ; and (iv) In cases where tracked customer activity may be double counted with activity that is not tracked at the customer level (
4 ) For EE programs with identified participants and those without (such as retail incentives to purchase energy

- efficient equipment), identify use EE program tracking data for the resulting overlap and ensure that MWh savings are only counted one time 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 EM&V plan must specify the EE savings verification approach approaches for ensuring that will be applied within the first year of implementation of the EE measures to ensure that the applicable EE measures have been properly installed, are is operating as intended, and therefore have has the potential to

save electricity . Verification must apply , 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 document reviews reviews of sales receipts and other documentation . If such approaches are documented in EM&V guidance issued by theAdministrator, t hey will be treated as acceptable

. (E) Interactive The i nteractive effects of EE program s, 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 the measurement boundary of the specific end

- uses(s) targeted by the EE program,
EE project, or EE measure (e.g., lighting retrofits to improve energy efficiency 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 or , EE project , or EE measure will be assessed , and must discuss the rigor of the met hod 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, and assess as well as the potential effects of progr am - or project

- specific circumstances in which such bias and error specified are likely to arise. Approaches to minimizing bias and error are provided in the EM&V plan guidance that may be issued by the Administrator will be acceptable

. (viii) If sampling will be used to quantify the electricity savings or the from an EE measure, program, then the MWh estimatesderived 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 q uantifying 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 (1)
. ”(2) [Reserved] **§ 62.16460 What are the requirements for monitoring and**  **verification reports for eligible resources?**  (a) M&V report requirements. Any M&V report that is submitted , in support of the issuance of an ERC that can be used in accordance with § 62.16420, must meet the requirements of this section. (b) General M&V report criteria. Each M& V report must include the following: ( 1 ) For the first M& V report submitted, documentation that the electricity

- generating resources, electricity

- saving measures, or practices were installed or implemented consistent with the description in the approved eligibility application required in § 62.164 4 5(a) ; and ( 2 ) F or each M&V report submitted: ( i ) I dentification 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 perio d to generate the quantified MWh of generation or MWh of electricity savings ; ( iii ) D ocumentation (including data) of the energy generation and/or electricity savings from any activity, project, measure, resource, or program addressed in the EM&Vreport, 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 ) D ocumentation 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 e ligible resource continued to meet all eligibility requirements during the reporting period covered by the M&V repor t 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 savi ngs capability of the qualifying eligible resource (including the date of the change) ; and ( v ) D ocumentation 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 repor t 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 Formatted: Don't add space between paragraphs of the same style, Adjust space between Latin and Asian text, Adjust space between Asian text and numbersobtaining 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
pena lties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment

. . ” **§ 62.16460 What are the requirements for monitoring and**  **verification reports for eligible resources?** (a) Any M&V report that is submitted in accordance with the requirements of §62.16445 , 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: (i) 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 el igibility application required in §62.16435(a). (ii) For each M&V report submitted: (A) identification of the time period covered by the M&V report, (B) a description of how relevant quantification methods, protocols, guidelines, and guidance specified in the EM&V planwere applied during the reporting period to generate the quantified MWh of generation or MWh of electricity savings, (C) documentation (including data) of the energy generation and/or electricity savings from any activity, project, measure, resource, or program addressed in the EM&V report, quantified and verified in MWh for the period covered by the M&V report, in accordance with its EM &V plan, and based on ex

- post energy generation or savings, (D) 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 resourc e 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 (E) documentation of any change in ownership interest of the qualifying eligible resource (including the date of the change). (d) You must ensure that any M&V report submitted pursuantto this subpart includes the following certification: (1) (2) [Reserved] 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 informatio n, 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 in formation, including the possibility of fine or imprisonment

. **§62.16465 Verification**  **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 o f 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 ac credited 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 theverification 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 (2) The following statement, signed by the

accr edited 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 personalknowledge 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 fa lse 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 b y 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

v alidity of the information submitted by the authorized account representative to demonstrate that the eligible resource meets each applicable requirement of § 62.16435 and **§** 62.16445(a). (2) The eligible resource is not duplicative of a resource used to meet emission standards or a state measure in another approved state S tate 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 e nergy resource to a renewable energy certificate tracking system). (6) Any other information required by the Administrator or that the accredited independent verifier finds, in its professional opinion, is necessary to assess the adequacy and validity of information and data supplied by the authorized account representative. (c) A verification report included as part of a M&V report must, at a minimum, describe the review conducted by the accredited independent verifier and verify the following: (1) The adequacy and validity of the information and data submitted in the submittal by the authorized account representative to quantify eligible MWh of electric generation or electricity savings during the period for which the authorized account representative s eeks 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 e ligible resource. (i) For metered generation, the data validity check must compare reported electricity generation to an engineeringestimate of the maximum generation potential of the qualified

renew able 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
genera tion, 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 t o assess the adequacy and validity of information and data supplied by the authorized account representative. **§ 62.16470**  **Accreditation of Independent Verifiers. 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 shallinclude include s a demonstration by the verifier that it meets the requirements in paragraph ( d). c ) of this section

. ( d c ) Independent verifiers must meet each of the requirements in paragraphs ( d c )(1) through (6) of this section to be accredited. (1) Independent verifie rs must have the skills, experience, resources (personnel and otherwise) to provide verification reports, including the following: ( A 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

. ; ( B ii ) Appropriate auditing and accounting qualifications for financial and non

- financial data monitoring, auditing, and quality assurance and quality control to evaluate the eligible resource for which the independent verifier is seeking accreditation

. ; ( C iii ) Knowledge of the requirements of the Administrator’s
state’s CO 2 Rate

- based Trading Program regulatio ns and related guidance

. ; ( D iv ) Knowledge of the eligible resource categories for which the independent verifier is seeking accreditation, including relevant aspects of the design, operation, and relatedenergy generation or electricity savings monitoring and reporting approaches for such eligible resources

. ; and ( E 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 managem ent 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 v erifiers 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 verificatio n team) and demonstrate that they meet the requirements of section § 62.16470(d)(1). Once accredited, only the accredited independent verification team identified in the accreditation application and accredited by the state S tate 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 resou rce 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 conflict s 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 Ineligib ility 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 C.F.R. CFR 50.5(q), through an insurance provider that possess a fina ncial 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 shall must disclose the level of profe ssional liability insurance they possess when entering into contracts to provide verification services pursuant to this regulation. ( e 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 a a n authorized account representative

. ; and (2) The instances specified in section 62.16475(d) are cause for revocation of a verif ier’s accreditation. **§ 62.16475 Avoidance of Conflict Interest with Accredited**  **Independent Verifiers. §**  **§ 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 eligible resource for which it has a conflict of interest or ( 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 e ligible resource, or any prospective Eligible eligible resource, for which the the y 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 eligible resource, that would impact their impartiality in assessing the va lidity 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 aneligible resource for which a a n authorized account
repres entative 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 (includ ing eligibility approval of an eligible resource, the quantified and verified MWh in an M&V report, ERC issuance, or the number of ERCs issued ). ) ; (5) Accredited independent verifiers must not own, buy, sell, or hold ERCs, or other financial derivatives related to ERCs, or have a financial relationship with other parties that own, buy, sell, or hold ERCs or other related financial derivatives

. ; (6) An accredited independent verifier must not be incapable of providing an impartial verification report for any other reason

. ; and (7) An accredited independent verifier must ensure that the subject of any verification report must not have the opportunity to review or influence any draft or final verification report before its submittal to the Administrator, and the accredited independent verifier must share any drafts of its reports with the Administrator at the same time as it shares them with the subject of the report.(b) A contract with an Eligible e ligible resource for the provision of verification services shall will not constitute a conflict of interest COI
. (c) Verification reports must include an attestation by the accredited independent verifier th at it evaluated and disclosed to the Administrator any potential COI related to an Eligible e ligible resource. (d) Prior to engaging for the provision of verification services, an accredited independent verifier must demonstrate that it has no conflict of i nterest COI related to the Eligible e ligible resource, as specified in §62.16475 paragraph (a ). ) of this section

. If a conflict of interest 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) below, of this section , then an accredited independent verifier may propose to the Administrat or steps that will be taken to eliminate the conflict of interest COI which shall 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 inverification services for an Eligible e ligible resource without the approval of the Administrator. (e) Pri or to engaging in verification services and writing a verification report, an accredited independent verifier shall must disclose to the Administrator all information necessary for the Administrator to evaluate a potential conflict of interest 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 conflict of interest COI ). (f) Accredited verifiers shall have an ongoing obligation to discl ose to the Administrator any facts or circumstances that may give rise to a conflict of interest COI as defined in §62.16475 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 conflict of interest COI as defined in §62.16475 paragraph (a ). ) of this section

. I f the Administrator rejects an accredited independent verifier report for such reasons, then the eligibility application or M&V report submittal must shall be deemed incomplete and ERCs must not be issued pursuant to it. **§ §**  **§ 62.16480**  **Revocation 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 conflict of interest COI with respect to an Eligible e ligible 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 alternat e designated**  **representatives play?** (a) Except as provided under §62.16495, each affected EGU, and each eligible resource shall have one and only onedesignated representative, with regard to all matters under the
CO 2 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 shall must act in accordance with the certification statement in § 62.16500(a)(4)(iii). (2) Upon and after receipt by the Administ rator 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 CO 2 Rate

based Trading Program, notwithstanding any agreement between the designated representative and such owners and operators; and (ii) The owners and operators of the affected EGU shall be bound by any de cision 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 shall must include a procedure for authorizing the alternate designated representative to act in lieu of the designated representative.(1) The alternate designated representative shall be selected by an agreement binding on the owners and operators of the affected EGU and shall must act in accordance with the certification statement in § 62.16500(a)(4)(iii). (2) Upon and after receipt by th e Administrator of a complete certificate of representation under §62.16500, (i) The alternate designated representative shall 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 Adminis trator regarding any such affected EGU. (c) Except in this section, §62.16570, and §§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?** (a) Except as provided under §62.16510 concerning delegation of authority to make submissions, each submission under the CO 2 Rate

- based Trading Progra m shall 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 shall 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 c ertify 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 inf ormation, 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

sec tion and §62.16510.**§ §**  **§ 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 da te 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 designa ted 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 previo us 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

. Formatted: Font: Not Bold, Underline

Formatted: Font: Not Bold, Underline(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 a nd 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 representati ve or any alternate designated representative shall 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 an y 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 shall must submit a certificate of representation under §62.16500 amending the list of affected EGUs to reflect the change. Formatted: Font: Not Bold, Underline

Formatted: Font: Not Bold, Underline Formatted: Font: Courier New(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 c ertificate of representation shall 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 shall 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 design ated representative shall must include the following elements inparagraphs (a)(1) through (5) of this section in a format prescribed by the Administrator : . (1) Identification of the affected EGU for which the certificate of representation is submitted, including names, source category and NAICS code (or, in the absence of a NAICS code, an equivalent code), State, plant code, county, latitude and longitude, un it 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 shall 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 affe cted EGU

. (4) The following certification statements by the designated representative and any alternate designated representative

— :(i) “I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators of the affected EGU .” ” ; (ii) “I certify that I have all the necessary authority to carry out my duties and responsibilities under the CO 2 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 o f transactions involving
CO 2 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 providedfor a different distribution of ERCs by contract, ERCs and proceeds of transactions involving CO 2 Rate

- based Trading Program ERCs will be deemed to be held or distributed in accordance with the contract.” (5) The signature of the designa ted 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. Th e 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 anyrepresentation, action, inaction, or submission of the designated representative or alternate designated representative or the finality of any decision or order by the Administrator

un der the CO 2 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 represe ntative, 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 dele gate, 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 he r 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, asappropriate, 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 delegat ion under 40 CFR **§** 62.16510(d) shall be deemed to be an electronic submission by me .” ” ; and Formatted: Font: Bold, Font color: Auto(ii) “Until this notice of delegation is superseded by another notice of delegation under 40 CFR **§** 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 40 CFR **§** 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 su perseding 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**  Formatted: Font: Bold, Font color: Auto

Formatted: Font: Bold, Font color: Auto**established and used ,**  **and how is ERC issuance documentation accessed?**  (a ) Compliance accounts. (1) Upon receipt of a complete certificate of representation under §62.16500, the Administrator will establish a compliance account for the affected EGU for which the certificate o f 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 authoriz ed 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 CO 2 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 Account 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 depos ited into it are permanently retired. Once an ERC is Formatted: Highlightretired, the ERC shall no longer be transferable to another account in that ERC tracking system or any other ERC tracking system. (2) [Reserved] (c) General accounts. (1) Application for a general account . (i) Designated representatives of affected EGUs, authorized account representatives of eligible resources, and any other person may apply to open a general account, for the purpose of holding and transferring ERCs, by submitting to the Administrat or a complete application for a general account. Such application shall 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 alter nate 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 s elected shall 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 shall must include the following elements in a f ormat 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 ide ntifying 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 au thorized 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 res ponsibilities under the CO 2 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 anydecision or order issued to me by the Administrator regardi ng 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 representa tive and alternate authorized account representative . (i) Upon receipt by the Administrator of a complete application for a general account under paragraph ( b c )(1) of this section, the Administrator will establish a general account for the person or
person s 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 CO 2 Rate

- based Trading Program, notwithstanding any agreement between the authorized account represent ative 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, ina ction, 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 al ternate authorized account representative by the Administrator regarding the general account. (ii) Except as provided in paragraph ( b c )(5) of this section concerning delegation of authority to make submissions, each submission concerning the general accou nt shall 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 shall 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 informationsubmitted 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 an d 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 i nclude 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 ( b c )(1) of this section. Notwithstanding any such change, all representatio ns, 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 authorizedaccount representati ve and the persons with an ownership interest with respect to the ERCs in the general account. (ii) The alternate authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (c)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate authorized account representative before the time and date when th e 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 i n 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 t o 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 A dministrator, as if the person were included in such list.(B) Within 30 days after any change in the persons having an ownership interest with respect to ERCs in the general account, including the addition or removal of a person, the authorized account re presentative or any alternate authorized account representative shall 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 ch ange. (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 Administrat or will rely on the application unless and until a superseding complete application for a general account under paragraph ( b c )(1) of this section is received by the Administrator. (ii) Except as provided in paragraph ( b c )(4)(i) of this section, no objectio n 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 sh all affect any representation, action, inaction, or submission of the authorized account representative or any alternate authorizedaccount representative or the finality of any decision or order by the Administrator under the CO 2 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

acco unt 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 representati ve 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 a ccount 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 subm ission to the Administrator in accordance with paragraph ( b c )(5)(i) or (ii) of this section, the authorized account representative or alternate authorized account representative, as appropriate, must submit to theAdministrator 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
rep resentative; (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 elect ronic submissions under paragraph ( b 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 agre e 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 alter nate authorized representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR **§** 62.16515( b c )(5)(iv) shall be deemed to be an electronic submission by me .”; ”; and Formatted: Font: Bold, Font color: Auto(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 40 CFR **§** 62.16515( b 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 40
CFR **§** 62.16515(c)(5) is terminated .”. .” (iv) A notice of delegation submitted under paragraph ( b 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 Administrato r 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, o r eliminate entirely any delegation of authority. (v) Any electronic submission covered by the certification in paragraph ( b c )(5)(iii)(D) of this section and made in accordance with a notice of delegation effective under paragraph (c)(5)(iv) of this sectio n 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 shall must include a correctly submitted ERC transfer under §62.16525 for any ERCs in the account to one or more other Allowance Managem ent 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 t o 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 identif ication. 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 **.** Afte r theestablishment 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 ( c)( 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 S tate in which it was issued and includes the year it was issued, and the eligible re source 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 repres entative name and information

. ; (3) Qualifying eligible resource identification number,

name, state S tate , 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 ) ;(5) The date the qualifying eligible resource commenced generation or saving of energy

. ; (6) Individual ERCs, each with a unique serial identi fier that meets the requirements of §62.16445(c). 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 de monstration

. ; (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
t hat 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 thegeneration of at least the following reports, [for as long as this regulation is effective] [in perpetuity]: (1) Account Activity Reports. By ea ch 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 acco unt 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 a ctivity 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, surrend er, and retirement for purpose of compliance with this regulation. (j) Interactions with other ERC tracking systems.

If approved in connection with a state S tate plan, then an Formatted: Indent: First line: 0.5", Add space between paragraphs of the same style, Don't adjust space between Latin and Asian text, Don't adjust space between Asian text and numbersERC tracking system may provide for transfers of ERCs to/from another ERC tracking system approved in connection with s
state S tate plan by the EPA, or provide for transfers of ERCs to/from an EPA

- administered ERC tracking system used to administer a fed eral 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 shall must submit the transfer to the Administrator. (b) An ERC transfer shall 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(2) When the Administrator attempts to record the transfer, the transferor account includes each ERC identified by serial number in the transfer. **§ §**  **§ 62.1**  **6530 When will ERC transfers be recorded?**  (a) Within five business days (except Except as provided in paragraph (b) of this section ) , w ithin 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.(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 transf er , ; and (2) The reasons for such non

- recordation. **§62.16535 How will deductions for compliance with a CO**  **2 emission**  **standard occur?** For affected EGUs subject to the emission standards listed in Table 1, the owner or operator of an affected EGU must demonstrate compliance with its CO 2 emission standard in accordance with 62.16420(c) and incorporate ERCs as listed in paragraphs (a) thro ugh ( e 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 CO 2 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, i n accordance with §62.16530, of ERC transfers submitted by the ERC transfer deadline for a compliance period, the Administratorwill 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 CO 2 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 CO 2 emission rate to eq ual the CO 2 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 accoun t. (c ) Identification of ERCs by serial number. (1) 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 ( d e ) of this section. In order to be complete, such request shall must be submitted to the Administrator by the ERC transfer deadline for such compliance period and include, in a format prescribed by the Administrator, the identification of the affected EGU and the appropriate serial numbers.( d ) First

- in, first

- out. The Administrator will deduct ERCs under paragraph (b) or ( e ) of this section from the affected EGU's compliance account in accordance with a complete request under paragraph (c)(1) of this section or, in the absence of such request or in the case of identification of an insufficient amount of ERCs in such request, on a first

- in, first

- out accounting basis. ( e ) Deductions for exceeding the emission standard. After making the deductions for compliance under paragraph (b) of this section for a compliance period in a year in which the affected EGU has exceeded its CO 2 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 y ear, equal to two times the number of
tons 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 ( d e ) of t his 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 a rate based or mass based an emission standard must prepare a monitoring plan in accordance with the applicable provisions in § 75.53(g) and (h) of this chapter, unless such a plan is already in place under another program that requires CO 2 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 CO 2 mass emissions (lbs). For the purposes of this subpart, substitute data recorded under part 75 of this chapter are not considered to be va lid 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 CO 2 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, m aintain, and calibrate a CO 2 continuous emissions monitoring system (CEMS) to directly measure and record CO 2 concentrations in the affected EGU exhaust gases emitted to the atmosphere and an exhaust gas flow rate monitoring system according to § 75.10(a)(3 )(i) of this chapter. As an alternative to direct measurement of CO 2 concentration, the owner or operator of an affected EGU may use data from a certified oxygen (O 2 ) monitor to calculate hourly average CO 2 concentrations, in accordance with §75.10(a)(3)(i ii) of this chapter. If CO 2 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 a n 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
CO 2 mass emission rate (tons/hr), either from Equation F

- 11 in Appendix F to part 75 of this chapter (if CO 2 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 CO 2 concentration is measured o n a dry basis). (iii) Next, multiply each hourly CO 2 mass emission rate bythe affected EGU or stack operating time in hours (as defined in §72.2 of this chapter), to convert it to tons of CO 2. Multiply the result by 2000 lb/ton to convert it to lb. (iv) The hourly CO 2 tons/hr values and affected EGU (or stack) operating times used to calculate CO 2 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 c alculate the hourly CO 2 mass emissions. (v) Sum all of the hourly CO 2 mass emissions values from that were calculated according to procedures specified in paragraph (a)(3)(ii) of this section over the entire compliance period. (vi) For each continuous mo nitoring system used to determine the CO 2 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 CO 2 mass emissions from the affected EGU; the owner or operator of an affected EGU must not apply the bias adjustment factors desc ribed 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 analternative to complying with paragraph (a)(3) of this section, determine the hourly CO 2 mass emissions according to paragraphs (a)(4)(i) through ( a)(4)( vi) of this section. (i) Implement the applicable procedures in appendix D to part 75 of this chapter to determine hourly affected EGU heat in put 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 chap ter to calculate the hourly CO 2 mass emission rate (tons/hr). (iii) For each valid operating hour (as defined in paragraph (a)(2) of this section, multiply determine the hourly tons/hr CO 2 mass emission rate from ( 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 it to it to tons of CO 2 . Then, multiply the result by 2000 lb/ton to convert it to lb. (iv) The hourly CO 2 tons/hr values and affected EGU (or stack) operating times used to calculate CO 2 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 calcul ate the hourly CO 2 mass emissions.(v) Sum all of the hourly CO 2 mass emissions values from 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 (F c ) using Equation F

- 7b in section 3.3.6 of appendix F to part 75 of this chapter, and may use these F c values in the emissions calculations instead of using the default F c values in the Equa tion 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, mai ntain 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 tocalculate the total CO 2 mass emissions, you must determine P net (the corres ponding 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 CO 2 mass emissions value is determined according to paragraph (a)(3) or (4) of this section, if there is no gross or net electrical output, but there is mechanical or useful thermal output, then you must still determine the net energy output for that hour. In addition, for an operating hour in which a valid CO 2 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 par tial 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 P net for your affected EGU using the following equation. All terms in the equation mus t 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.PP nnnnnn = ( PPPP ) SSSS + ( PPPP ) CC + ( PPPP ) IIII − ( PPPP ) FFFF TDF ( PPPP ) SSSS + ( PPPP ) CC + ( PPPP ) IIII − ( PPPP ) AA TDF + [ ( PPPP ) PP + ( PPPP ) HHHH + ( PPPP ) IIII ]
Where:
P net = Net energy output of your affected EGU for each valid operating hour (as defined in paragraph ( a)( 2 )) ) of this section ) in MWh. (Pe) ST = Electric energy output plus mechanical energy output (if any) of steam turbines in MWh. (Pe) CT = Electric energy output plus mechanical energy output (if any) of stationary combustion turbine(s) in MWh. (Pe) IE = Electric energy output plus mechanical energy output (if any) of your affected EGU’s integrated equipment that provides electricity or mechanical energy to the affected EGU or auxiliary equipment in MWh. (Pe) FW A = Electric energy used to power boiler feedwater pumps at steam generating units 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, orenhance the performance of the affected EGU. This is calculated using the equation specified in paragraph (a)(5)( ii 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 affecte d EGU (for example, for combined heat and power), then you must calculate (Pt) PS using the following equation: ( PPPP ) PP = QQ mm × HH CCCC 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. Q m = 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 10 9 J/MWh or 3.413 x 10 6 Btu/MWh. (C) Sum all of the valu es of P net over the entire compliance period. Then, divide the total CO 2 mass emissions from paragraph (a)(3)(v) or (a)(4)(v ), ) of this section , as applicable, by the sum of the P net values to determine the CO 2 emissions emission rate(lb/net MWh) for the c ompliance 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 t he hourly CO 2 mass emissions at the common stack in lieu of monitoring each EGU separately. If an owner or operator of an affected EGU chooses this option, then the hourly net electric output for the common stack must be the sum of the hourly net electric output of the individual affected EGUs and the operating time must be expressed as “stack operating hours” (as defined in § 72.2 of this chapter). (7) In accordance with § 60.13(g), if the exhaust gases from an affected EGU implementing the continuous emissi ons monitoring provisions in paragraph (a)( 2 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 CO 2 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 b y summing the CO 2 mass emissions measured at theindividual 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 hourl y net electrical load to the individual EGUs according to the fraction of the total heat input contributed by each EGU. (b) [Reserved] **§62.16545 May I bank CO**  **2 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 §62.16208( b), § § § 62. 16530, § 62.16535 , §62.16540 , 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 Management Tracking and Compliance System account. Within 10business 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 ( d 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 incl ude the following information, as applicable in the quarterly reports: (i) The percentage of valid operating hours in each quarter described 62.16540(a)(2) (i.e., the total number of valid operating hours) in that period divided by the total number of
oper ating hours in that period, multiplied by 100 percent); and (ii) The hourly CO 2 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 (P net ) values for each valid operating hour in the compliance period ,; ; (iv) The calculated CO 2 mass emissions (lb) for each valid operating hour in the compliance period; Formatted: Indent: First line: 0"(v) The sum of the hourly net energy output values and the sum of the hourly CO 2 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); and (vii) The calculated CO 2 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 CO 2 emission standard (as identified in Table 1) with which your affected EGU must comply, your CO 2 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 representativ e 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
meet s 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 t he 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 cha pter (as applicable). Operating hours in which CO 2 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 r epresentative of each affected EGU at the facility shall must make all submissions required under the
CO 2 Mass 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 reportingrequirements and submi t 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 CO 2 to meet the ap plicable emission standard, then you must report in accordance with the requirements of 40 CFR Part p art 98 Subpart , s ubpart PP , of this chapter and either: (1) Report in accordance with the requirements of 40 CFR
Part p art 98 , subpart RR, of this chapter , if injection occurs

on - site; or (2) Transfer the captured CO 2 to an affected EGU or facility that reports in accordance with the requirements of 40 CFR
Part p art 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. (2) For affected EGUs under this subpart that are not in the Acid Rain Program, you must also meet the reporting requirements and submi t 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. For affected EGUs under this subpart that are not in the Acid Rain Program, youmust 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 requ ired under this subpart. (4) 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 (c)(3) of this section, 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
app endix D to part 75 of this chapter (as applicable). Operating hours in which CO 2 mass emission rates are calculated using maximum potential values are not “valid operating hours” (as defined in §6 2
. 16 540(a)), and shall not be used in the compliance determi nations under § 62.16434
. (3) A person (or persons) authorized by the DR or ADR under §72.26 of this chapter to make the required submissions. **§ 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 Formatted: No widow/orphan control, Tab stops: 0.5", Left + 1", Left + 1.5", Left + 2", Left + 2.5", Left + 3", Left + 3.5", Left + 4", Left + 4.5", Left + 5", Leftperiod, occurrence, measurement, maintenance, corrective action, report, or record. (1) Unless otherwise provided, the owner or operator of an

a ffected 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 five years, in writing by the Administrator. (i) The certif icate of representation under §62.16500 for the designated representative for each affected EGU and all documents that demonstrate the truth of the statements in the certificate of representation; provided that the certificate and documents shall must be re tained 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 com pliance with an affected EGU’s emission standard under § 62.16420 and any other requirements of the CO 2 Rate

- based Trading Program. ( iii iv ) Data that is required to be recorded by 40 CFR
Part p art 75 Subpart , s ubpart F , of this chapter

. ( iv 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 ( c)(2)(iv a )( 1 )( v )(A) and (B) of this section. (A) All documents related to any ERCs used in a compliance demonstration, including each eligibility application, EM&V plan, M&V report, and independent verifier verification report associated with the issuance of each specific ERC, and each regulatory approval and any documentation that supports the issuance of e ach 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 CO 2 Rate

- based Trading Program and make appropriate adjust ments 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 )(1 ) of this section, and record such deductions and transfers. **Definitions §**  **62.16570 What definitions apply to this subpart?**  The terms used in this subpart shall have the meanings set forth in this section as follows: Acid Rain Program means a multi

- state SO 2 and NO X air pollution control and emission red uction program established by the Administrator under title IV of the Clean Air Act and parts 72 through 78 of this chapter. Administrator means the Administrator of the United States Environmental Protection Agency or the Director of the Clean Air Markets Division (or its successor determined by the Administrator) of the United States Environmental Protection Agency, the Administrator's duly authorized representative Formatted: Space After: 8 ptunder his or her delegate, or the authorized state official under an approved state plan th at incorporates this subpart. Affected electric generating unit or Affected EGU means a
any steam generating unit, integrated gasification combined cycle ( IGCC ), , or stationary combustion turbine that meets the relevant applicability conditions requirements in section §62.16410
. §§60.5840( b) and 60.5845 of this chapter. An affected EGU is not an eligible resource. Allowable CO 2 emission rate means, for an affected EGU, the most stringent State or federal CO 2 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 one year. Allowance Tracking and Compliance System means the system by which the Administrator records allocations, deductions, and transfers of ERCs under the CO 2 Rate

- based Trading Program. Such allowances are allocated, recorded, held, deducted, or transferred only as whole allowances ERCs
. Allowance Tracking and Compli ance System account means an account in the Allowance Management System established by the Administrator for purposes of recording the allocation, holding, transfer, or deduction of ERCs.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 au thorizations 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. ERC transfer deadline means, for a compliance period in a given year, midnigh t 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 CO 2 emission standard for such compliance period in accordance with §§62.16420 and 62.16535. Alternate designated representative means, for a CO 2 Rate

b ased 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 CO 2 Rate

- based Trading Program. If the affected EGU is also subjectto the Acid Rain Program, TR NO X Annual Trading Program, TR
NO X Ozone Season Trading Program, TR SO 2 Group 1 Trading Program,
or TR S O 2 Group 2 Trading Program, then this natural person shall be the same natural person as the alternate designated representative, as defined in the respective program. Annual capacity factor means the ratio between the actual heat input to an EGU during a calendar year and the potential heat input to the EGU had it been operated for 8,760 hours during a calendar year at the base load rating. Also see capacity factor. Authorized account representative means, for a general account, the natural person who is authorized, in accordance with this subpart, to transfer and otherwise dispose of ERCs held in the general account and, for a CO 2 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, root s) above and belowground, and available on a renewable or recurring basis. Materials that are biologically based include non

- fossilized, biodegradable organic material originating from modern or contemporarily grown plants, animals, or microorganisms (incl uding 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 f rom the decomposition of non

- fossilized and biodegradable organic material). Boiler means an enclosed fossil

- or other

- fuel

- fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or other medium. Business day means a day that does not fall on a weekend or a federal holiday.Capacity factor means, as used for the output based set

aside, the ratio of the net electrical energy produced by a generating unit for the period of time considered to the electrical energy that could have been produced at continuous net summer capacity during the same period. Certifying official means a natural person who is: (1) For a corporation, a president, secretary, treasurer, or vice

- president of the corporation in charge of a principal business function or any other person who performs similar policy

- or decisio n - 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 . CO 2 emissions limitation means the tonnage of CO 2 emissions authorized in a compliance period in a given year by the CO 2 allowances available for deduction for the affected E GU under §62.16535(a) for such compliance period.
CO 2 Rate

- Based Trading Program means a multi

- state CO 2 air pollution control and emission reduction program established in accordance with this subpart and subpart UUUU of part 60 of thischapter (including such a program that is revised in a State Plan p lan or state allowance distribution methodology, or by the Administrator under subpart UUUU of part 60 of this chapter , as a means of controlling CO 2 emission s. Coal means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see §60.17), coal refuse, and petroleum coke. Synthetic fuels derived from coal for the purpose of creating useful heat, including but not limited to solvent

- refined coal, gasified coal (not meeting the definition of natural gas), coal

- oil mixtures, and coal

- water mixtures are included in this definition for the purposes of this subpart. Coal

- derived fuel means any fuel (whether in a solid, liquid, or gaseous state) produced by the mechanical, thermal, or chemical processing of coal. 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 p ower unit or CHP unit, (also known as “cogeneration”) means an electric generating unit that use asteam

- generating unit or stationary combustion turbine to simultaneously produce both electric (or mechanical) and useful thermal output from the same primar y 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 stand ard or market

average 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 deli very 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 CO 2 allowances available for use for a compliance period in a given year in complying with the affected
EGU's CO 2 emission standard in accordance with §§62.16420 and 62.16535. Compliance period means the multi

- year periods starting January 1 of the first calendar year of the period, except asprovided in §62.16420(c)(3), and ending on December 31 of the last calendar year, inclusive: (1) Compliance Period 1 means the period of three calendar years from January 1 2022 to December 31, 2024

. ; (2) Compliance Period 2 means the period of three calendar years from January 1, 2025 to December 31, 2027

. ; and (3) Compliance Per iod 3 means the period of two 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 provid e, 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 CO 2 emissions, stack gas volumetric flow rate, stack gas moisture content, and
O 2 concentration (as ap plicable), in a manner consistent with part 75 of this chapter and §§ § 62. xx30 through 62.xx35. 16540(a)(3)
. The following systems are the principal types of continuous emission monitoring systems: (1) A flow monitoring system, consisting of a stack flow rate monitor and an automated data acquisition and handling Formatted: Font color: Autosystem 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

H 2 O; (3) A CO 2 monitoring system, consisting of a CO 2 pollutant concentration monitor (or an O 2 monitor plus suitable mathematical equations from which the CO 2 concentration is derived) and an automated data acquisition and handling system and providing a permanent, continuous record of CO 2 emissions, in percent CO 2 ; and (4) An O 2 monitoring system, consisting of an
O 2 concentration monitor and an automated data acquisition and handling system and providing a permanent, continuous record of
O 2 , in percent O 2 . Control area operator means an electric system or systems, bounded by interconnection metering and telemetry, capable of controlling gener ation to maintain its interchange schedule with other control areas and contributing to frequency regulation of the interconnection. Deemed savings means estimates of average annual electricity savings for a single unit of an installed demand

side EE measu re that (a) has been developed from data sources Formatted: Font: 12 pt
Formatted: Font: 12 pt

Formatted: Font: 12 pt(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 para meters 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

- si de 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 Efficien cy e nergy e fficiency 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 a system or equipment modification or to discounting a portion of a generating units capacity for planning purposes. Designated representative means, for a CO 2 Rate

- based Trading affected EGU and each affected EGU at the affected EGU, the natural person wh o 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 Formatted: Font: Courier New, 12 ptbind each owner and operator in matters pertaining to the CO 2 Rate

- based Trading Progr am. If the CO 2 Rate

- based Trading affected EGU is also subject to the Acid Rain Program, TR
NO X Annual Trading Program, TR NO X Ozone Season Trading Program,
TR SO 2 Group 1 Trading Program, or TR SO 2 Group 2 Trading Program, then this natural person shall b e 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 rati ng and ISO conditions. Distillate oil means fuel oils that comply with the specifications for fuel oil numbers 1 and 2, as defined by the American Society of Testing and Materials in ASTM D396 (incorporated by reference, see §60.17); diesel fuel oil numbers 1 and 2, as defined by the American Society for Testing and Materials in ASTM D975 (incorporated by reference, see §60.17); kerosene, as defined by the American Society of Testing and Materials in ASTM D3699 (incorporated by reference, see §60.17); biodiesel as defined by the American Society of Testing and Materials in ASTM D6751 (incorporated by reference, see §60.17); or biodiesel blends as defined by the American Society of Testing and Materials in ASTM D7467 (incorporated by reference, see §60. 17). Formatted: Font: 12 pt Formatted: Font: 12 pt Formatted: Font: 12 pt Formatted: Font: 12 ptEffective useful life or 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

c hange in electricity use resulting from the implementation of

an d emand

- side EE measure . Eligibile Eligible resource means a resource that meets the requirements of § 62.16435 and has been registered with the EPA

administered ERC tracking system or an ERC tracking system approved in a State plan by the EPA

. An eligible resource is not an affected EGU

.

. EM&V plan means a a n evaluation measurement and verification plan that meets the requirements of § 62.16455
. Emissions means air pollutants exhausted from an affected
EGU or 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 Formatted: Font: Not Italic

Formatted: Font: Italic

Formatted: Font color: Auto Formatted: Font: Not Italic

Formatted: Font: Bold(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. Eligible resource Emission r at e c redit ( ERC ) means a

resource 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. , 62.16435 and has been registered with the EPA

- administered ERC tracking system or an ERC tracking system approved in a state plan by the
EPA . An eligible resource is not an affected EGU

. 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 CO 2 emission standard). Energy e fficiency program or EE program means organized activities sponsored and funded by a particular entity to promote the adop tion of one or more EE project or EE measure for the purpose of reducing electricity use. Energy e fficiency 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 Formatted: Font: Not Italic Formatted: Font color: Text 1 Formatted: Font color: Text 1

Formatted: Font color: Auto Formatted: Font: Not Italicreducing electricity use; EE projects may be implemented as part of an EE program or as an independent privatel y - funded action. Energy e fficiency m easure 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

- fu nded 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. 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 orderto be available for use in complying with the affected EGU's CO 2 emission standard for such compliance period in accordanc e with §§62.16420 and 62.16535. 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

accor dance with this subpart. 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 emissio ns means any ton of emissions from the affected EGUs at a a n affected EGU during a compliance period that exceeds the CO 2 emissions limitation for the affected EGU for such compliance period. Existing state program, requirement, or measure means, in the context of a state S tate plan, a regulation, requirement, program, or measure administered by a state, utility, or otherentity that is currently established. This may include a regulation or other legal requirement that includes past,

curren t, and future obligations, or current programs and measures that are in place and are anticipated to be continued or expanded in the future, in accordance with established plans. An existing state program, requirement, or measure may have past, current, an d future impacts on EGU CO 2 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 cont inues thereafter. The final period is comprised of final compliance periods, each of which is two calendar years (with a calendar year beginning on January 1 and ending on December 31). Final Compliance Period c ompliance p eriod means a compliance period wit hin the final period, each being two 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 natural gas, pe troleum, coal, and any form the definition as defined in subpart TTTT of solid, liquid, or gaseous fuel derived from such material for the purpose part 60 of creating useful heat this chapter

. Fossil

- fuel

- fired means, with regard to an affected EGU, combusting any amount of fossil fuel. Gaseous fuel means any fuel that is present the definition

as a gas at ISO conditions and includes, but is not limited to, natural gas, refinery fuel gas, process gas, coke

- oven gas, synthetic gas, and gasified coal. def ined in subpart TTTT of part 60 of this chapter

. General account means an Allowance Management 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 fromthis 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 thi s 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 Formatted: Font: Italicwith or without duct burners. Indian country means “Indian country” as defined in 18 U.S.C. 1151. Integrated gasification combined cycle facility or IGCC facility means a combined cycle facility that is designed to burn fuels containing 50 percent (by heat input) or more solid

derived fuel not meeting the definition of natural gas plus any integrated equipment that provides electricity or useful therm al 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 fue l is directly burned in the unit during operation. Interim period means the period of eight calendar years from January 1, 2022 to December 31, 2029. The interim period is comprised of three compliance periods, compliance period 1, compliance period 2, and compliance period 3. ISO conditions means 288 Kelvin (15 o C), 60 percent relative humidity and 101.3 kilopascals pressure. Liquid fuel means any fuel that is present the definition as a liquid at ISO conditions and includes, but is not limited to, distill ate oil and residual oil. 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 i s not used to operate the affected facility, generate electricity and/or thermal output, or to enhance the performance of the affected facility. Mechanical energy measured in horsepower hour should be converted into MWh by multiplying it by 745.7 then divi ding 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 chapte r. 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 ope ration (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 Formatted: Font: Courier New, 12 ptof any subsequent physical change in the generator resulting in an increase in the maximu m 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 a fluid mixture of hydrocarbons (e.g., methane, ethane, or propane), composed of at least 70 percent methane by volume or that has a gross calorific value between 35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic foot), that maintains a gaseous state under ISO conditions. In addition, natural gas contains 20.0 grains or less of total sulfur per 100 standard cubi c feet. Finally, natural gas does not include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coal

- derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable sulfur content or heating value. Natural gas means the definition as defined in subpart TTTT of part 60 of this chapter

. Net

- electric output means the amount of gross generation the generator(s) produce (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gasexpander(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 con trol 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 heat ing application ) ; and
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 tran sformer (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 ). (2) For combined heat and power facilities where at least 20.0 percent of the total net energy outpu t 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 s ummer c apacity means the maximum output, commonly expressed in megawatts (MW), that generating equipmen t 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 CO 2 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 affect ed EGU or the affected EGU and shall include include s , but is not be limited to, any holding company, utility system, or plant manager of such affected EGU or affected EGU.
Owner means, for a CO 2 Rate

- based Trading affected EGU or an affected EGU at a a n aff ected EGU respectively, any of the following persons: (1) Any holder of any portion of the legal or equitable title in an affected EGU at the affected EGU or the affected
EGU; (2) Any holder of a leasehold interest in an affected EGU at the affected EGU or the affected EGU, provided that, unless expressly provided for in a leasehold agreement, “owner” shall not include a passive lessor, or a person who has an equitable interest through such lessor, whose rental payments are not based (either directly or indirectly) on the revenues or income from such affected EGU; and ( 3) Any purchaser of power from a affected EGU at the affected EGU or the affected EGU under a life

- of

- the

- unit, firm power contractual arrangement. Permitting authority means “permitting authority” as defined in §§70.2 and 71.2 of this chapter.Petroleum means crude oil or a fuel derived from crude oil, including, but not limited to, distillate and residual oil. Qualifying 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 pe rmanent retirements. Petroleum means the definition as defined in subpart TTTT of part 60 of this chapter

. Qualif ied biomass means a biomass feedstock that is demonstrated to qualify as a method to control increases of CO 2 levels in the atmosphere. Random error means errors occurring by chance that may cause electricity savings values to be inconsistently overestimated or underestimated, and may result from a change in electricity use due to unaccounted

- for factors that affect electricity use. The ma gnitude 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, wit h regard to ERCs, the moving of ERCs by the Administrator into, out of, or between Allowance Management Tracking and Compliance System accounts, for purposes of allocation, transfer, or deduction. Reference method means any direct test method of sampling

an d analyzing for an air pollutant as specified in §75.22 of this chapter. Replacement , replace , or replaced means, with regard to an affected EGU, the demolishing of an affected EGU, or the permanent retirement and permanent disabling of an affected EGU, and the construction of another affected EGU (the replacement affected EGU) to be used instead of the demolished or retired affected EGU (the replaced affected EGU). Solid fuel means any fuel that has a definite shape and volume, has no tendency to flow or disperse under moderate stress, and is not liquid or gaseous at ISO conditions. This includes, but is not limited to, coal, biomass, and pulverized solid fuels. the definition as defined in subpart TTTT of part 60 of this chapter

.Solid waste incineration unit means a stationary, fossil

fuel

- fired boiler or stationary, fossil

- fuel

- fired combustion turbine that is a “solid waste incineration unit” as defined in section 129(g)(1) of the Clean Air Act. 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 press ure (SATP) conditions means 298.15 Kelvin (25 o C, 77 o F )) ) and 100.0 kilopascals (14.504 psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is 50 Btu/lb. State agent means an entity acting on behalf of the
state S tate , with the legal authority of the state S tate . State measures means measures that the state S tate 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 S tate 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 emissionscontrol technology, and any ancillary components and sub

components comprising any simple cycle stationary combustion turbine, any combined cycle combustion turbine, and any combined h eat 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 no t 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. Stationary combustion turbine means all equipment, including but not limited to the turbine engine, the fuel, air, lubrication and exhaust gas systems, control systems (except emissions control equipment), heat recovery system, fuel compressor, heater, and/or pump, post

- combustion emissions control technology, and any ancillary components and sub

components comprising any simple cycle stationary combustion turbine, any combined cycle combustion turbine, and any combined heat and power combustion turbine based system plus any integrated equipment that provides electricity or useful thermal output to the combustion turbine engine, heat recovery system or auxiliary equipment. Stationary means that the combustionturbine is not self

- propelled or intended to be propelled w hile performing its function. It may, however, be mounted on a vehicle for portability. If a stationary combustion turbine burns any solid fuel directly it is considered a steam generating unit. Steam generating unit means any furnace, boiler, or other dev ice used for combusting fuel and producing steam (nuclear steam generators are not included) plus any integrated equipment that provides electricity or useful thermal output to the affected facility or auxiliary equipment. Submit or serve means to send or transmit a document, information, or correspondence to the person specified in accordance with the applicable regulation: (1) In person; (2) By United States Postal Service; or (3) By other means of dispatch or transmission and delivery; (4) Provided that compliance with any “submission” or “service” deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt. Transmission and distribution loss means the difference between the quantity of electricity that serve s a load (measured at the busbar of the generator) and the actual electricity useat 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 efficienc y 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 un it operation means, with regard to an affected EGU, an hour in which the affected EGU combusts any fuel. Uprate means a n 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 affec ted 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 theaffected 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 electric ity to customers. Valid data means quality

- assured data generated by continuous monitoring systems that are installed, operated, and maintained according to part 75 of this chapter. For CEMS, the initial certification requirements in §75.20 of this chapter and appendix A to part 75 of this chapter must be met before quality

- assured data are reported under this subpart; for on

going quality assurance, the daily, quarterly, and semiannual/annual test requirements in sections 2.1, 2.2, and 2.3 of appendix B to part 75 of this chapter must be met and the data validation criteria in sections 2.1.5, 2.2.3, and 2.3.2 of appendix B to part 75 of this chapter apply. For fuel flow meters, the initial certification requirements in section 2.1.5 of appendix D to part 75 of this chapter must be met beforequality

- 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 or WTE means a process or unit (e.g., solid waste incineration unit) that burns recovers energy from the biogenic fraction conversion or combustion of waste stream materials, such as municipal solid waste (which is considered a qualifying biomass feedstock) , to generate electricity and/ or heat. **§62.16575 Measurements, abbreviatio ns, 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
CO 2 — carbon dioxide
COI

— conflict of interest
CVR

- conservative voltage regulation
DR

- designated representative

EE

— energy efficiency Formatted: Font: Courier New, 12 pt

Formatted: Indent: First line: 0.5"EGU

- electric generating unit
EM&V

- - evaluation, measurement, and verification
GCV

- gross calorific value
GJ

- giga joule
H 2 O

— water hr

— hour
IGCC

- i ntegrated 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
O 2 — oxygen
mmBtu

—million Btu
MWe

— megawatt electrical MWh

— megawatt hour
T&D

- transmission and distribution
O 2 — oxygen PSD

- prevention of significant deterioration
yr — year Formatted: Font color: Auto

Formatted: Font color: Black

Formatted: Font color: Black**Table 1 to Subpart NNN of Part 62 —**  **CO 2**  **Emission Standards (Pounds**  **of CO 2**  **Per Net MWh)**

**Compliance Period Affected steam**  **generating unit or integrated**  **gasification combined cycle**  **(IGCC) emission standards**  **Affected stationary combustion turbine**  **emission standard**

C ompliance Period 1 (2022

- 2024) 1,671 877 C ompliance Period 2 (2025

- 2027) 1,500 817 Compliance Period 3 (2028

- 2029) 1,380 784 Final Compliance Period s 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 Period s .26

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**PART 78**  **-- APPEAL PROCEDURES**  6 . The authority citation for Part 78 continues to read as follows: **Authority:** 42 U.S.C. 7401 et seq. Formatted: Font: Bold

Formatted: Indent: First line: 0"7 . Section 78.1 .27 is amended by r evis ing paragraph (a)(1) and add ing paragraphs (b ) (1 8 ) and (b)(1 9 ) to read as follow follows : a. by revising paragraphs (a)(1) ; and b. by adding paragraphs (b)(16) and (b)(17).
§ 78.1 Purpose and scope. (a)(1) This part shall govern appeals of any final decision of the Administrator under subparts MMM and NNN of part 62 of this chapter, part 72, 73, 74, 75, 76, or 77 of this chapter, subparts AA through II of part 96 of this chapter or State regulations approved under §51.123(o)(1) or (2) of this chapter, subparts AAA th rough 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 und er §51.123(o)(1) or Formatted: Indent: First line: 0"(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) * * * ( 16 1 8 ) Under subpart MMM of part 62 of this chapter, (i) The decision on allocation of CO 2 allowances under §62.162 40 of this chapter. (ii)The decision on allocation of CO 2 allowances from set

asides under §62.162 45 of this chapter. (iii) The decision on the transfer of CO 2 allowances under
§ 62.16330 of this chapter. (iv) The decision on the de duction of CO 2 allowances under §62.16 340 of this chapter. (v) The correction of an error in an Allowance Tracking and Compliance System account under §62.16 355 of this chapter. (vi) The adjustment of information in a submission and the decision on the ded uction and transfer of CO 2 allowances based on the information as adjusted under §62.16 370 of this chapter. (vii) The finalization of compliance period emissions data, including retroactive adjustment based on audit. ( 17 1 9 ) Under subpart NNN of part 62 of this chapter, (i) The decision on emission rate credit issuance, adjustment and revocation under §6 2
. 16435(ii) The decision on qualification status of eligible resources to receive emission reduction credits under §6 2
. 16460
. (iii) The decision on revocation of qualification status of an eligible resource under §6 2
. 16440
. (iv) The decision on Adjustments for error or misstatement, suspension of ERC issuance under §6 2
. 16450
. (v) The decision on accreditation of independent verifiers under § 6 2
. 16470
. (vi) The decision on revocation of accreditation status under § 6 2
. 16480
. (vii) The decision on the transfer of emission reduction credits under §62.16 530 of this chapter. (viii) The decision on the deduction of emission reduction credits under §62. 165 35 16 16535 of this chapter. (ix) The correction of an error in an Allowance Tracking and Compliance System account under §62.16 550 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 §62.16 565 of this chapter. (xi) The finalization of compliance period emissions data, including retroactive adjustment based on audit.

* * * * *