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

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

c. A dd ing paragraph s (g) through (k)

. The revisions , deletion, and additions read as follows: § 60.27 Actions by the Administrator.

* * * * * (b) After receipt of a complete plan or complete plan revision, the Administrator will propose the plan or revision for approval or disapproval. The Administrator will, within 12 months after the date on which the submission of a plan or plan revision is received , approve or disapprove such plan or revi sion , or each portion thereof. (c) The Administrator shall promulgate a federal plan within 12 months after the date the Administrator :(1) F inds t he S tate fail ed to submit a complete plan or complete plan revision within the time prescribed; or (2) [R eserved ] ( 3 ) D isapproves the 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 unde r 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 approve s . After the promulgation of a federal plan, t he Administrator may

approve a 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 corresponding emission guideline(s) specified in the final guideline document published under § 60.22(a) and will require final compliance with such standa rds as expeditiously as practicable but no later than the times specified in the guideline document.

* * * * *(g) Completeness c riteria. (1) General

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

. In order to be complete, a
S tate plan must contain each of the following administrative criteria : ( i ) A formal letter of submittal from the Governor or her designee requesting EPA approval of the plan or revision thereof; ( ii ) Evidence that the S tate has adopted the plan in the

s tate code or body of regulations. That evidence shall include the date of adoption or final issuance as well as the effective date of the plan, if different from the adoption/issuance date;( iii ) Evidence that the S tate has the necessary legal authority under s tate law to adopt and implement the plan; ( iv ) A copy of the actual regulation, or document submitted for approval and incorporation by reference into the plan. The submittal shall 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 S tate. The effective date of the regulation or document shall, whenever possible, be indicated in the document itself. The S tate’s electronic copy must be an exact duplicate of the hard copy. For revisions to the approved plan, the submittal shall indicate the changes made (for example, by redline/strikethrough) to the approved plan; ( v ) Evidence that the S tate followed all of the procedural requirements of the s tate's laws and constitution in con ducting and completing the adoption and issuance of the plan; ( vi ) Evidence that public notice was given of the proposed change with procedures consistent with the requirements of 40 CFR 60.23, including the date of publication of such notice; ( vii ) Certif ication that public hearing(s) were held in accordance with the information provided in the public notice and the S tate's laws and constitution, if applicable and consistent with the public hearing requirements in 40 CFR 60.23;( viii ) Compilation of public comments and the S tate's response thereto ; and ( ix ) Such other criteria for completeness as may be specified by the Administrator under the applicable emission guidelines. (3) Technical criteria

. In order to be complete, a S tate plan must contain each of the following technical criteria: ( i ) Description of the plan approach and geographic scope; ( ii ) Identification of each affected source, identification of emission standards for the affected sources, and monitoring, recordkeeping and reporting requirements that will determine compliance by each affected source; ( iii ) Identification of compliance schedules and/or increments of progress; ( iv ) Demonstration that the S tate plan submittal is projected to achieve emissions performance under the applic able emission guidelines; ( v ) Documentation of s tate recordkeeping and reporting requirements to determine the performance of the plan as a whole; and ( vi ) Demonstration that each emission standard is quantifiable, non

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

. A State may submit a 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 to the criteria in this paragraph apply to plans submitted explicitly for parallel processing: ( i ) T he lette r required by paragraph (g)(2)( i ) shall request that EPA propose approval of the proposed plan by parallel processing; ( ii ) I n lieu of paragraph (g)(2)( ii ) the State shall submit a schedule for final adoption or issuance of the plan; ( iii ) I n lieu of par agraph (g)(2)( iv ) the plan shall include a copy of the proposed/draft regulation or document, including indication of the proposed changes to be made to the existing approved plan, where applicable; and ( iv ) T he requirements of paragraphs (g)(2)(E) through (I) shall 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 be met prior to publication o f EPA’s final determination of plan approvability. (h) Full and p artial a pproval and d isapproval. If a portion of the plan revision meets all the applicable requirements ofthis chapter, the Administrator may approve the plan revision in part and disapprove the plan revision in part. The Administrator may authorize partial plan submissions in conjunction with a federal plan, where in combination, the federal and S tate plans constitute a complete and approvable plan meeting all of the requirements of this subpart and the applicable emissions guidelines. (i ) Conditional 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 appropriate S tate plans , or otherwise commit to making changes in the S tate’s plan necessary to meet the requirements of the applicable emission guidelines. Any such conditional approval shall automatically convert to a disapproval if the State fails to comply with such commitment by the date certain establish ed by the Administrator. ( j ) Calls for 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 require the S tate to revise the plan as necessary to correct such inadequacies. The Administrator shall notify the State of the inadequacies, and may establishreasonab le deadlines (not to exceed 18 months after the date of such notice) for the submission of such plan revisions. Such findings and notice shall be public. Any finding under this paragraph shall, to the extent the Administrator deems appropriate, subject the State to the requirements of this part to which the State was subject when it developed and submitted the plan for which such finding was made, except that the Administrator may adjust a ny dates applicable under such requirements as appropriate. ( k ) Error 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 promulgation revise such action as appropriate without requiring any further submission from the State. Such determination and the basis thereof shall be provided to the State and pu blic.

* * * * * **PART 62 --**  **APPROVAL AND PROMULGATION OF STATE PLANS FOR**
**DESIGNATED FACILITIES AND POLLUTANTS** 3 . The authority citation for 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 requirements apply to affected EGUs that retire? **General Requirements** 62.16220 What requirements must I comply with? 62.16225 How should I compute time under the CO 2 Mass

- based Trading Prog ram? 62.16230 What are the administrative appeal procedures? 62.16231 What is the Clean Energy Incentive Program? **Emission Goals, Set -**  **Asides, and Allowance Allocations** 62.16235 What are the statewide mass

- based emission goals , renewable energy set

- asides, output

- based set

- asides , and Clean Energy Incentive Program early action set

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

- aside allowances allocated? 62.16250 What is the process for revocation of qualification status o f 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?62.16 275 What is the accreditation procedure for independent verifiers? 62.16280 What are the procedures accredited independent verifiers must follow to avoid conflict of interest? 62.16285 What is the process for the revocation of accreditation status for an independent verifier? **Designated Representatives** 62.16290 How are designated representatives and alternate designated representatives authorized? What role do authorized designated representatives and alternate designated representatives play? 62.16295 What responsibilities do designated representatives and alternate designated representatives hold? 62.16300 What are the processes for changing designated representatives, alternate designated representatives, owners and operators, and affected EGUs at the facility? 62.16305 What must be included in a certificate of representation? 62.16310 What is the Adminis trator’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 Ho w 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** 62.1 6375 What definitions apply to this subpart? 62.16380 What measurements, abbreviations, and acronyms apply to this subpart?

**Introduction §**  **62.16205 What is the purpose of this subpart?** ( a) This subpart sets forth the requirements for the Clean Power Plan (CPP) CO 2 Mass

- based Trading Program, under section 111 of the Clean Air Act and subpart UUUU of p art 60 of this chapter, as a means of meeting emission guidelines limiting greenhouse gas emissions from an affected steam generatin g unit, integrated gasification combined cycle (IGCC), or stationary combustion turbine. (b) The pollutants regulated by this subpart are greenhouse gases. The greenhouse gas limitations in this subpart

are in the form of an emission standard for carbon dioxide (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 un der section 111 of the Act” is considered to be the pollutant that otherwise is subject to regulation under the Act as defined in §51.166(b)(48) and in any state implementation plan approved bythe EPA that is interpreted to incorporate, or specifically in corporates, § 51.166(b)(48) of this chapter. (2) For the purposes of §52.21(b)(50)(ii) of this chapter , with respect to GHG emissions from affected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” is cons idered to be the pollutant that otherwise is subject to regulation under the Act as defined in §52.21(b)(49) of this chapter. (3) For the purposes of §70.2 of this chapter, with respect to greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” is considered to be the pollutant that otherwise is "subject to regulation" as defined in 40 CFR §70.2 of this chapter. (4) For the purposes of §71.2 of this chapter , with respect

t o greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” is considered to be the pollutant that otherwise is "subject to regulation" as defined in 40 CFR §71.2 of this cha pter. **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 ) locatedwithin a S tate that has incorporated by reference this subpart

as a S tate plan, or portion of a S tate plan, that has been approved by the Administrator and is effective under subpart UUUU of p art 60 of this chapter, or if this subpart is promulgated and effective as a federal plan in your S tate under

p art 62 of this chapter. (b) An affected EGU is any steam generating unit, IGCC , or stationary combustion turbine that meets the applicability

req uirements in § §60.5840(b) and 60.5845 of this chapter. **§62.1621 5**  **What requirements apply to affected EGUs that retire?**  **?** (a) Exemption

. (1) Any affected EGU that is permanently retired as defined in § 62.16375 is exempt from § §62.16220(c)(1) [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 will become effective on the first day of the compliance peri od immediately following the compliance period in which the retirement took effect. Within 30 days of the affected EGU's permanent retirement, the designated representative must submit a statement to the Administrator. The statement must state, in a format prescribed by the Administrator, that the affected EGU was permanently retired on a specified date and will comply with the requirements of paragraph (b) of this section.(b) Special provisions

. (1) An affected EGU exempt under paragraph (a) of this secti on must not emit any CO 2 , starting on the date that the exemption takes effect. (2) For a period of 5 years from the date the records are created, the owners and operators of an affected EGU exempt under paragraph (a) of this section must retain, at the fa cility that includes the unit, records demonstrating that the affected EGU is permanently retired. The 5

- year period for keeping records may be extended for cause, at any time before the end of the period, in writing by the Administrator. The owners and

op erators bear the burden of proof that the affected EGU is permanently retired. (3) The owners and operators and, to the extent applicable, the designated representative of an affected EGU exempt under paragraph (a) of this section must comply with the requ irements of the CO 2 Mass

- based Trading Program accruing during a ny compliance periods for which the exemption is not in effect, even if such requirements 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 must have a designated representative, and may have analternate designated representative, in accordance with §§62.16290 through 62.16300. (b) Emissions monitoring, reporting, and recordkeeping requirements. (1) The owners and operators, and the designated representative, of each facility and each affected EGU at the facility must comply with the monitoring, reporting, and recordkee ping requirements of § §62.16345 62.16360, and 62.16365. (2) The emissions data determined in accordance with
§ § 62.16345, 62.16360, and 62.16365 must be used to calculate allocations of CO 2 allowances under §§62.16240(a)and (b) and to determine compliance w ith the CO 2 emission standard under paragraph (c) of this section, provided that, for each monitoring location from which mass emissions are reported, the mass emissions amount used in calculating such allocations and determining such compliance must be th e mass emissions 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 must hold, in the facility's compliance account,
CO 2 allowances availabl e for deduction for such compliance period under §62.16340(a) in an amount not less than the tons of totalCO 2 emissions for such compliance period from all affected EGUs at the facility. (ii) If total CO 2 emissions during a compliance period in a given ye ar 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 must hold the CO 2 allowances requi red for deduction under §62.16340(d); and (B) The owners and operators of the facility and each affected EGU at the facility are subject to federal enforcement pursuant to sections 113(a) through (h), and section 304, of the
CLEAN AIR ACT , and the United States, 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 must pay any fine, p enalty, or assessment or comply with any other remedy imposed, for the same violations, under the CLEAN AIR
ACT , and each ton of such excess emissions and each day of such compliance period will constitute a separate violation of this subpart and the CLEAN AIR ACT
. (2) Compliance periods. (i) An affected EGU will be subject to the requirements under paragraph (c)(1) of this section forthe compliance 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 compliance period or for a year in a prior compliance period. (ii) A CO 2 allowance held for compliance with the requirements under 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 must be held i n, 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 authorizati on is limited in its use and duration as follows: (i) Such authorization must only be used in accordance with the CO 2 Mass

- based Trading Program; and(ii) Notwithstanding any other provision of this subpart, the Administrator has the authority to terminate or limit the use and duration of such authorization to the extent the Administrator determines is necessary or appropriate to implement any provision of the CLEAN AIR ACT
. (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

are applicable requirements that must be included in an affected EGU’s title V permit. (2) The applicable requirements of this subpart, as well as other terms or conditions necessary to ensure compliance with the applicable requirements, may be added to, or changed in, a title V permit using minor permit modification procedures in accordance with §§70.7(e)(2) and 71.7(e)(1) of this chapter, provided that such changes do not conflict with any existing terms of the permit. This paragraph explicitly provides that the addition of, or change to, an affected EGU's description as described in the prior sentence is eligible for minor permit modification proce dures 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 be required for any allocation, holding, deduction, or transfer of CO 2 allowances inaccordance with this subpart, provided that the requ irements applicable to such allocations, holdings, deductions, or transfers of CO 2 allowances are already incorporated 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

t he designated representative of affected EGUs at a facility shall 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 t he designated representative of an affected EGU shall also apply 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 exempt ing or excluding the owners and operators, and the designated representative, of an affected EGU from compliance with any other provision of the applicable, approved

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?** (a) Unless otherwise stated, any time period scheduled, under the CO 2 Mass

- Based Trading Program, to begin on theoccurrence of an act or event will begin on the day the act or

event occurs. (b) Unless otherwise stated, any time period scheduled, under the CO 2 Mass

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

- Based Trading Program, is not a business day, then the time period is extended to the next business day. **§ 62.16230 What are the administrative appeal proc**  **edures?** 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**  **What is the Clean Energy Incentive Program?** (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 AC T . The Administrator will award, on behalf of each such state, early action allowances 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 implemented in or benefitting the state from theeffective date of a federal plan for that state until December 31, 2021: (1) Metered wind power; (2) Metered solar power; and (3) Demand

- side EE that benefits low

- income communities. (b) Early acti on allowances will be distributed pursuant to a process to be prescribed by the Administrator, from an allowance set

- aside equal to 300 million allowances for all states. This set

- aside does not increase the total budget of allowances for the affected EGUs in the state subject to this subpart. (c) The Administrator will match these early action allowances with additional matching allowances pursuant to a process to be prescribed by the Administrator. Matching awards will be made up to a limit equivalent t o 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, th e 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 matchingallowances the Administrator determines to be equivalent to two MWh from the match under paragraph (c) of this section

. (2) For EE projects that benefit low

- income communities as determined by the Administrator solely for purposes of this subpart: for every two MWh in end

- use demand savings achieved, the project wi ll receive a number of early action allowances the Administrator determines to be equivalent to two MWh from the

set

- aside under paragraph (b) of this section and a number of matching allowances the Administrator determines to be equivalent to two MWh from the match under paragraph (c) of this section

. **Emission Goals, Set -**  **Asides, and Allowance Allocations §**  **62.16235 What are the statewide mass -**  **based emission goals, renewable energy set**  **- asides, output**  **- based set**  **- asides**  **, and Clean Energy Incentive Program**  **early action set -**  **asides ?**  (a) The statewide mass

- based emission goals with renewable energy set

- asides and output

- based set

- asides for allocations of
CO 2 allowances for the interim 3

- and 2

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

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

**Table 1 to Subpart MMM of Part 62**  **-- Statewide Mass**  **- based Emission**  **Goals*** **(short tons) Interim Period**  **Final Period State**  **Compliance Period 1 2022**  **- 2024**  **Complia nce**  **Period 2**  **2025 -**  **2027 Complia**  **nce Period**  **3 2028**  **- 2029**  **Final complianc**  **e periods 2030**  **- 2031**  **and thereafte**  **r** Alabama 66,164,470 60,918, 973 58,215, 989 56,880,47 4 Arizona 36,032,671 32,953, 521 31,253, 744 30,322,63 2 Arkansas 35,189,232 32,371, 942 30,906, 226 30,170,75 0 Californi a 53,500,107 50,080, 840 48,736, 877 48,410,12 0 Colorado 35,785,322 32,654, 483 30,891, 824 29,900,39 7 Connectic ut 7,555,787 7,108,4 66 6,955,0 80 6,941,523

Delaware 5,348,363 4,963,1 02 4,784,2 80 4,711,825

Florida 119,380,477 110,754 ,683 106,736 ,177 105,094,7 04 Georgia 54,257,931 49,855, 082 47,534, 817 46,346,84 6 Idaho 30,408,352 27,615, 429 25,981, 975 25,018,13 6 Illinois 1,615,518 1,522,8 26 1,493,0 52 1,492,856

Indiana 80,396,108 73,124, 936 68,921, 937 66,477,15 7

Iowa 92,010,787 83,700, 336 78,901, 574 76,113,83 5Kansas 26,763,719 24,295, 773 22,848, 095 21,990,82 6 Kentucky 76,757,356 69,698, 851 65,566, 898 63,126,12 1 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 21,700,58 7 Lands of the Uintah and Ouray Reservati on 2,758,744 2,503,2 20 2,352,8 35 2,263,431

Louisiana 42,035,202 38,461, 163 36,496, 707 35,427,02 3 Maine 13,360,735 12,511, 985 12,181, 628 12,104,74 7 Maryland 17,447,354 15,842, 485 14,902, 826 14,347,62 8 Massachus etts 2,251,173 2,119,8 65 2,076,1 79 2,073,942 Michigan 56,854,256 51,893, 556 49,106, 884 47,544,06 4 Minnesota 27,303,150 24,868, 570 23,476, 788 22,678,36 8 Missi ssip pi 67,312,915 61,158, 279 57,570, 942 55,462,88 4 Missouri 28,940,675 26,790, 683 25,756, 215 25,304,33 7

Montana 13,776,601 12,500, 563 11,749, 574 11,303,10 7Nebraska 60,975,831 55,749, 239 52,856, 495 51,266,23 4 Nevada 25,453,173 23,095, 610 21,708, 108 20,883,23 2 New Hampshire 22,246,365 20,192, 820 18,987, 285 18,272,73 9 New Jersey 4,461,569 4,162,9 81 4,037,1 42 3,997,579

New Mexico 18,241,502 17,107, 548 16,681, 949 16,599,74 5 New York 14,789,981 13,514, 670 12,805, 266 12,412,60 2 North Carolina 15,076,534 14,072, 636 13,652, 612 13,523,58 4 North Dakota 35,493,488 32,932, 763 31,741, 940 31,257,42 9 Ohio 88,512,313 80,704, 944 76,280, 168 73,769,80 6 Oklahoma 47,577,611 43,665, 021 41,577, 379 40,488,19 9 Oregon 9,097,720 8,477,6 58 8,209,5 89 8,118,654 Pennsylva nia 106,082,757 97,204, 723 92,392, 088 89,822,30 8 Rhode Island 3,811,632 3,592,9 37 3,522,6 86 3,522,225 South Carolina 31,025,518 28,336, 836 26,834, 962 25,998,96 8 South Dakota 4,231,184 3,862,4 01 3,655,4 22 3,539,481(b) If implementing interstate trading, then the Administrator will use the sum of a covered group of S tates’

mass - based emission goals as the aggregate mass

- based emission goal. (c) The renewable energy set

- aside for each S tate covered by the federal mass

- based emissions trading plan must reserve 5 percent from the State’s annual allowances prior to allocation Tennessee 34,118,301 31,079, 178 29,343, 221 28,348,39 6

Texas 221,613,296 203,728 ,060 194,351 ,330 189,588,8 42 Utah 28,479,805 25,981, 970 24,572, 858 23,778,19 3 Virginia 31,290,209 28,990, 999 27,898, 475 27,433,11 1 Washingto n 12,395,697 11,441, 137 10,963, 576 10,739,17 2 West Virginia 33,505,657 30,571, 326 28,917, 949 27,986,98 8 Wisconsin 62,557,024 56,762, 771 53,352, 666 51,325,34 2 Wyoming 38,528,498 34,967, 826 32,875, 725 31,634,41 2 * 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

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

- aside.of that year’s allowances to facilities. The renewable energy

set

- aside s are 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

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( d ) The output

- based set

- aside for each S tate under this subpart, beginning in compliance period 2, must reserve a share of the State’s annual allowances prior to allocation of that year’s allowances to facilities as set forth in this paragraph 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

- asides are specified in Ta ble 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 Nebraska 144,635 Nevada 2,326,529 New Hampshire 542,721 New Jersey 3,413,100 New Mexico 627,085 New York 3,815,381 North Carolina 2,120,178 North Dakota 0Ohio 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 S tate covered under this subpart must contain an amount of allowances shown in T able 4 to this subpart , which must reserve a share of the State’s annual allowances prior to allocation of that year’s allowances to facilities as set forth in this paragraph

.

**Table 4**  **to Subpart MMM of Part 62 --**  **. Clean Energy Investment**  **Program Early Action Set -**  **Aside (short tons)**  **State** Allowances in Early Action Set

aside (short tons) Alabama 3,122,306 Arizona 1,719,618 Arkansas 2,187,230 California 218,846 Colorado 2,223,192 Connecticut 69,415 Delaware 138,392 Florida 3,230,248 Georgia 2,755,623Idaho 14,929 Illinois 5,968,721 Indiana 5,754,076 Iowa 2,191,183 Kansas 2,115,630 Kentucky 4,952,862 Lands of the Fort Mojave Tribe 5,885 Lands of the Navajo Nation 1,623,066 Lands of the Uintah and Ouray Reservation 175,509 Louisiana 1,497,428 Maine 20,739 Maryland 972,775 Massachusetts 170,471 Michigan 3,727,861 Minnesota 2,002,903 Mississippi 357,307 Missouri 3,771,322 Montana 1,310,344 Nebraska 1,481,695 Nevada 336,288 New Hampshire 107,798 New Jersey 446,005 New Mexico 823,049 New York 557,771 North Carolina 2,674,590 North Dakota 2,150,635 Ohio 4,788,372 Oklahoma 2,067,006 Oregon 154,353 Pennsylvania 5,039,346 Rhode Island 35,674 South Carolina 1,652,802 South Dakota 264,207 Tennessee 2,178,084 Texas 10,400,192 Utah 1,401,189 Virginia 1,386,546 Washington 751,434 West Virginia 3,506,890 Wisconsin 2,393,870 Wyoming 3,104,324(2) Allowances may be distributed from the set

- aside for projects meeting the criteria of paragraph (e) (3) of this section , upon application of a project proponent that meets the requirements of 62.16245(a), except as may be prescribed by the Administrator in a future action. In order to receive a distribution, the project proponent must establish a general account in the tracking system as provided in 62.16320(c). (3) Projects eligible for distribution of allowances from this set

- aside must meet each of the criteria in paragraphs (e)(3)(i) through (ii i ) of this section. All categories of resources other than those listed in paragraphs (e)(3)(iii)(A) and (B) of this section, and all provisions of this subpart relating to such resources, are not available o r 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) T he creditable generation or energy savings from the project must occur in calendar years 2020 or 2021; and (iii) G eneration or energy savings must be from one of the following types of sources capable of revenue

- quality m etering: (A) Onshore wind; (B) S olar; or(C) D emand

- side EE

. **§62.16240 When are allowances allocated?**  (a) Allowance allocations **.** (1) By June 1, 2021, and by June 1 of each year prior to the beginning of each compliance period thereafter, 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 notice or this subpart . Providing an allocation to an entity does not constitute as an applicability determination of an affected EGU

. (2) Notwithstanding paragraph (a)(1) of this section, if an affected EGU which is provided an allocation does not operate for two consecutive calendar years, then such affected EGU will

not be allocated the CO 2 allowances provided by the Administrator in a notice or this subpart 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 parag raph (a)(1) of this section, if an affected EGU provided an allocation in a notice of this subpart issued by the Administrator is modified or reconstructed suchthat it is no longer subject to this subpart, then such affected EGU will not be allocated the CO 2 allowances provided for the affected EGU for the next compliance period for which allowances have not yet been recorded and for each compliance period after that compliance period. All 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. (b) Set

- asides. (1) Renewabl e 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 ( 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 S tate, in accordance with §62.16245(a)( 6 ) and ( 7 ) for the generation year of the applicable calculation, and will promulgate a notice of data availability of the results of the calculations. (2) Output

- based s et

- asides

. (i) By November 1 of the first

year o f each compliance period beginning in 2025, and eachcompliance period thereafter, the Administrator will calculate and allocate the CO 2 allowance allocation to each affected EGU in a State, in accordance with §62.16245(b)(3), for the generation period of the applicable calculation deadline under this paragraph. (ii) By November 1 of the first year of each compliance period beginning in 2025, and each compliance period thereafter, the Administrator will calculate and allocate the CO 2 allowance allocation to each affected EGU in a State, in accordance with §62.16245(b)(4) and (5) for the generation period of the applicable calculation, and will promulgate a notice of data availability of the results of the calculations. (c) Affected EGUs incorrectly allocated CO 2 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 unde r 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 therecipient and will act in accordance with the procedures set forth in paragraphs (c)(2) through (5) of this section: (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 period that the state allowance distribution methodology provides should be allocated onl y 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 p rovision 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 recipient 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 approved under subpart UUUU of part 60 of this chapter, the recipient is not actually an affe cted EGUas 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 provides should be allocated only to recipients that are affected EGUs as of January 1 of such compliance period. (2) Except as provided in paragraph (c)(3) or (4) of this section, the Administrator will not record such CO 2 allowances under §62.16325. (3) If the 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 shal l 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 the determination under paragraph (c)(1) of this section after making deductions for the facility that includes such recipient under §62.16340(b) for such compliance period, then theAdministrator 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 allowances 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 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 com pliance period in accordance with such state allowance distribution methodology. (ii) With regard to the CO 2 allowances that were not allocated from a renewable energy or output

- based set

- aside for such compliance period and that are not recorded, or that are deducted as an incorrect allocation, in accordance with paragraphs (c)( 2 ) and ( 3 ) of this section for a recipient under paragraph (c)(1)(ii) of this paragraph, 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 allow ances in the portion of the CO 2 allowances that may be allocated for such compliance 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

- ba sed set

- aside for such compliance period and that are not recorded, or that are deducted as an incorrect allocation, in accordance with paragraphs (c)(2) and (3) of this section for a recipient under paragraph (c)(1)(ii) of this paragraph, the Administrato r will transfer such CO 2 allowances back to the renewable energy set

aside, or to the output

- based set

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

- aside . The Administrator w ill establish a renewable energy set

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

- aside for each year of a co mpliance period as outlined in this section. (2) Eligible r enewable e nergy c apacity. To be eligible to receive renewable energy set

- aside allowances, an eligible resource must meet each of the requirements in paragraphs (a)(2) (i) through (v) of this section

. Any resource that doesnot 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, solar , geothermal power, or utility scale hydropower. ( ii) The resources must only include resources which increased new installed electrical generation nameplate capacity, or new electrical savings measures installed or implemented after January 1, 2013. If a resource had a nameplate capacity uprate, then set

- aside allowances may be issued only for the difference in generation between the uprated nameplate capacity and its nameplate capacity prior to the uprate. 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 capacity and is not an eligible resources, unless it receives a capacity uprate as a result of the relicensing process that is reflecte d in its relicensed permit. In such a case, only difference in nameplate capacity between its relicensed permit and its prior permit is eligible to be issued set

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

- based S tate for which the se t

- 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 Emission Rate Credits (ERCs) for any period of t ime for which it receives set

aside allowances. (3) Process for issuance of set

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

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

. (i) Eligibility application. To receive set

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

- mail address, telephone number, a nd allowance tracking system account number ; and (B) Identification of the eligible resource(s), including the physical location of the eligible resource; contact information for the owner or operator of the eligible resource, if different from the authori zed account representative anddesignated 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, custome r - sited distributed generator) (if applicable) ; facility and generating unit IDs (EIA ORIS Code, Facility Registration System (FRS) Code, if applicable) (if applicable) ; the control area, balancing authority, ISO conditions as defined in § 62.16375 (if applicable) , or regional transmission organization ( RTO ) 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 E IA

- 860 (if applicable)

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

- aside allowances to the Administrator by June 1 of the year prior to the ge neration year for which set

- aside allowances are requested. Providers may update submitted projections for future generation years, these projections must be received by June 1 of the year prior to the generation year in question. The project application s hall contain the following information: ( A ) Projection of the project’s annual renewable energy generation in MWh.( B ) Documentation of the methodology, data facilities, and assumptions used to project the project’s annual renewable energy generation. ( C ) A certification that the eligibility application has only been submitted to the Administrator or pursuant to an EPA

approved multi

- S tate approach where S tates are providing for joint issuance of allowances pursuant to the authority in their individual S tate plans. ( D ) A evaluation, measurement, and verification ( EM&V ) plan. ( E ) A verification report from an accredited independent verifier who meets the requirements of §62.16275 and §62.16280. While considered a part of the eligibility application, the

v erification report must be submitted separately by the accredited independent verifier to the Administrator. ( F ) An authorization that provides for the following: the Administrator may inspect (including a physical inspection of the eligible resource and i ts meter) and/or audit the eligible resource at any time and verify that the eligible resource and the EM&V plan have been implemented as described in the eligibility application. ( G ) The following statement, signed by the authorized account representativ e of the eligible resource:( 1 ) “ I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my personal knowledge and/or inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitti ng false statements and information or omitting required statements and information, including the possibility of fine or imprisonment. ” ( 2 ) [Reserved] ( H ) Any other information required by the Administrator.

( 4 ) Monitoring and 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) A measurement and verification ( M&V ) report. (ii) A verification report from an accred ited independent verifier that meets the requirements of §62.16275 and §62.16280. While considered a part of the M&V report, the verification report must be submitted separately by the accredited independent verifier to the Administrator.( 5 ) Allocation of Renewable Energy Set

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

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

aside allowances for a generation year with the number of allowances distributed to each project prorated according to its percentage of the total approved projected MWhs for that S tate that the project represents. (ii) If in the previ ous 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 project ed hours for the generation year, then the Administrator will carry over the deficit and subtract from the projected generation in subsequent years until there is no deficit. If this deficit is greater than 10 percent in a particular year, then the provide r 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 Administr ator will disqualifythe provider from receiving future set

- asides for the following compliance period. ( 6 ) Surplus r enewable s et

- aside a llowances. If, after completion of the procedures under paragraph (a)( 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 w ere 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); and continues to be allocated CO 2 allowances for such compliance period in accordance with §62.16 240(a)(2). ( 7 ) Notice of s urplus r enewable e nergy s et

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

- based 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 year of a compliance period as set forth in §62.16235(c).(2) Unit e ligibility . To be eligible to receive output

based set

- aside allowances, affected EGUs must meet the following eligibility requirements: (i) The af fected 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 abo ve 50 percent based on net summer capacity and net generation. (3) Allocation of o utput

- based s et

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

- aside allowances for each eligible EGU based on its average net generation and

net summer c apacity 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 generation in the preceding compliance period over 50 percent mult iplied 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 wil l provide notice of the net summer capacity and net generation data used, and the resultingallocations by August 1 of the first year of each compliance period beginning in 2025. The notice of the net summer capacity and net generation data used, and the r esulting allocations, shall allow 30 days for public comment on the data and allocations, until August 31 of the same year. (iv) The Administrator will provide notice of the final

set

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

- based 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 A dministrator 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 a vailability issued under §62.16240(a)(1); and continues to be allocated CO 2 allowances for such compliance period in accordance with §62.16240(a)(2 )

. (5) Notice of s urplus o utput

- based s et

- aside. The Administrator will notify the public, through the promulgation of the notices of data availability described in §62.16240 (b)(1) and (2) , of the amount of CO 2 allowances allocated under paragraphs (b)(3) and (4) of this section for such compliance peri od to each affected EGU eligible for such allocation.**§ §62.16250 What is the process for revocation of qualification**  **status of an eligible resource?** (a) If an eligible resource is found to not meet the requirements of §62.16260 in the CO 2 M ass - based 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 applic ation or M&V report may be cause for revocation of the qualification status of an eligible resource. (c) Repeated instances of error or misstatement of MWh of electricity generation or savings in submitted M&V reports, and any other requirements may be cau se 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 ac count representative of the eligible resource, the Administrator may prohibit the eligible resource from any further eligibility to be issued allowances. In addition, the provisions of §62.16255(a) through (d) may apply

. **§ §62.16255 What is the process for**  **error adjustments or misstatement, and suspension of allowance issuance?** (a) In the event of error or misstatement of quantified MWh of electricity generation or savings in a previous M&V report for which set

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

- aside allowances issued in a subsequent reporting period to address the error or misstatement, by subtracting a number of MWh from the quantified and verified MWh in the M&V report for the subsequent reporting period. In the event that an error or inadvertent misstatement occurs in a final M&V report for an eligible resource, for which

set

- aside allowances have been issued, the provisions of paragraph (b) of this section will apply. (b) In the event of error or misstatement of quantified MWh of electricity generation or savings in the final M&V report for an eligible resource, for which set

- aside allowances have been issued, the Administrator will revoke set

- aside allowances from the general account held by the authorized account representative of the eligible resource, in an amount necessary to correct the error or misstatement. In the event that the general account of the eligible resource holds an insufficient number of set

- aside al lowances to correct the error or misstatement, the authorized account representative shall 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 res ult in prohibition ofthe authorized account representative for the eligible resource from further participation in the program, unless reauthorized at the discretion of the Administrator. (c) The Administrator may freeze the general account held by an aut horized account representative of an eligible resource at any time, for cause, if the Administrator determines set

aside allowances have been improperly issued, based on a misrepresentation or misstatement in an eligibility application or M&V report. The A dministrator may also freeze the general account of 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 Administra tor may take the actions in paragraphs (d) (i) through (iii) of this section

. (i) Freeze the general account of the authorized account representative eligible resource, preventing any transfers of allowances out of the account. (ii) Revoke or deduct allowan ces held in the general account of the authorized account representative eligibleresource, 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 hold s a number of allowances less than the number of

set

- aside allowances issued for the ineligible eligible resource, the delegated representative of an eligible resource shall submit to the Administrator within 30 days a number of allowances necessary to ful ly 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 Administ rator. (e) The Administrator may temporarily or permanently suspend issuance of set

- aside allowances for an eligible resource, for the following reasons in paragraphs (e) (i) through (iii) of this section. (i) Pending investigation of potential misrepresentation, error, or misstatement in an M&V report, for which set

- aside allowances have been issued, or the eligibility status of an eligible resource. (ii) In the case of repeated error or misstatements in submitted M&V reports. (iii) In the case of an intentional misrepresentation in a submitted M&V report.**Evaluation Measurement and Verification Plans, Monitoring and Verification Reports, and Verification**  **§ §**  **62.16260 What are the requirements for evaluation measurement and verification plans for**  **eligible resources?** (a) EM&V plan requirements. Any EM&V plan submitted in support of the issuance of a set

- aside allowance pursuant to this rule must meet the requirements of this section. (b) General EM&V plan criteria. Each EM& V plan must identify the eligible resource and its approved eligibility application. (c) Specific EM&V plan criteria. Each EM&V plan must provide the manner in which the electricity generated or saved by the eligible resource will be quantified, monitored and verified, and the manner of quantification, monitoring and verification must meet the criteria listed in paragraphs (c)(1) through (7) of this section, as applicable to the specific eligible resource. (1) For a nuclear energy resource or a renewable e nergy 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) throu gh (vi) of this section must be met. (i) The generation data is physically measured on acontinuous basis using a revenue

- quality meter, which shall mean a meter used by a control area operator for financial settlements, or a meter that meets the American National Standards Institute No. C12.20. , Code for Electricity Metering, metering accuracy standards, or a meter that meets an alternative equivalent standard that has been approved in advance of its use to measure generation pursuant to this regulation by the EPA. (ii) The generating data is measured at the generator’s bus bar, or, for a renewable energy resource with a nameplate capacity of less than 10 kW that is interconnected behind an individual business or household meter, the generating data was

mea sured 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 o ne eligible resource generating unit may be associated with each meter, and generation data may not be aggregated, unless all the following provisions are met: (A) All of the generating units have the same essential generation characteristics ; (B) All of the generating units are located in the same
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 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 qualit y assurance procedures. (iv) The generation data is collected electronically and telemetered from the generator to its control area operator and verified through a control area energy accounting or settlement process which occurs at least monthly, unless the generation unit does not go through a control area operator, in which case the generation data must be collected by manual meter readings conducted by an independent verifier that is either not affiliated with the owner or operator of the qualifying

r enewable energy generating resource or is precluded pursuant to the relevant 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 enable monthly reporting, the data may be self

- reported and reported no less than annually.(v) The generation data serves a load that otherwise would have been served by the grid if not for the generator. Spec ifically: (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 interconne ction ; and (B) For generators interconnected to transmission systems and with on

- site loads other than station service drawing generation before the metering point, set

- aside allowances may be issued for on

- site load, if the owner or operator of the eligi ble 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 S tate plan pursuant to which that EM&V plan is submit ted. (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 thedistribution 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
S tate; (C) The nameplate capacity of the individual units being aggregated is each less than 150 kW, and units coll ectively do not exceed a total nameplate capacity of 1 MW when aggregated, or alternative requirements approved by the EPA in connection with the specific S tate plan pursuant to which that EM&V plan or M&V report is submitted; and (D) The generation data a re 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 an d a resource study (wind, shading, solar irradiance, depending on the resource), or engineering information that takes into account the capacity, age, and type of qualifying energy generating resource, and all input parameters and assumptions must be clear ly delineated, or if the generating unit does notgenerate 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

- base d 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 eli gible resource to the transmission or distribution grid, and is not based on the generation used on

- site by the customer. (vii) Any other requirements approved by the EPA in connection with the specific S tate plan pursuant to which that EM&V plan is submit ted. (3) For qualif ied biomass feedstocks used, in addition to the requirements of paragraph (c)(1) or (2) of this section, whichever section is applicable, each EM& V plan must demonstrate that the requirements approved by the Administrator for that biomass feedstock and its associated biogenic CO 2 in connection with that S tate plan have been met. (4) For a waste

— to

- energy resource, in addition to the requirements of paragraph (c)(1) or (2) of this section, as applicable, and paragraph (c)(3) of this section, each EM&V plan must specify: (i) The total net energy generation from the resource inMWh; (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; 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 su bmitted 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 requirement 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) of this section , as applicable, and any other requirements approved by the EPA in connection with the specific S tate plan pursuant. (i) If the combi ned 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 of this subpart. (ii) If the combined heat and power unit has an electric generating capacity less than or equal to 25 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 andreporting methodology in 40 CFR 75. (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 di stribution loss rate (expressed as a percentage) from the most recent year that is published in the US EIA State Electricity Profile expressed as a percentage. No other transmission and distribution loss factors may be used in calculating the electricity s avings, including measures such as conservation voltage reduction and volt/VAR optimization. (7) Each EM&V plan for an EE program or project must specify how each of the following requirements will be met in quantifying the electricity savings from that EE program or project: (i) All electricity savings must be quantified on an ex

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

- time basis, which means at the time the electricity savings are occurring. Electricity savings mu st not be quantified on an ex

- ante basis, which means estimates of MWh savings that are generated prior to implementing the subject EE activity, and that are not quantified using EM&V methods and procedures.(ii) All electricity savings must be quantified and verified based on methods and procedures detailed in an industry best

- practice EM&V protocol or guideline . Each EM&V plan must include a demonstration of how the best

- practice protocol or guideline was selected and will be applied to the specific EE

AP MP covered in the E&V plan, and an explanation of why that

p articular protocol or guideline was selected. Protocols and guidelines are considered to be best practice if they: (A) Have gone through a rigorous and credible peer review process that shows the applicable methods to be valid through empirical testing (B) Have been accepted and approved for use by identifiable state regulatory commissions Examples of such protocols and guidelines are provided in the EM&V guidance issued by the Administrator

. (i ii) All electricity savings must be quantified as the difference between the observed electricity use and a common practice baseline (CPB), which is the equipment that would typically have been installed

– or that a typical consumer or building owner would have continued using

– in a given circumstance (i.e., a given building type, EE program type or delivery mechanism, and geographic region) at the time of EE implementation. Examples of CPBs for specific EE programs and projects, and for certain EM&V metho ds, are provided in the EM&Vguidance issued by the Administrator. The EM&V plan must specify the reason the specific CPB was selected for that EE program or project , which must include an analysis of the appropriateness of that CPB for the EE measure covered in the EM&V plan , based

on : (A) Characteristics of the EE program or project ; (B) The delivery mechanism used to implement the EE program or project (e.g., installed as part of a utility program direct install program versus a point

- of

- sale rebat e) ; (C) Local consumer and market characteristics ; (D) Applicable building energy codes and standards and average compliance rates ; and (E) The method applied: project

- based measurement and verification (PB

- MV), comparison group approaches, or deemed savin gs. (iv) All electricity savings must be quantified by applying one or more of the following methods: project

- based measurement and verification (PB

- MV), comparison group approaches, or deemed savings. (A) If a comparison group approach is used, then the EM&V plan must quantify electricity savings by taking the difference between a comparison group’s electricity use and the electricity use of EE program participants. Comparison group approaches may inclu de randomized control trials and quasi

- experimentalmethods, as described in industry best

- practice protocols and guidelines, and in the EM&V guidance issued by the Administrator. (B) If deemed savings are used, then the EM&V plan must specify that the de emed savings values will only be used for the specific EE measure for which they were derived. The EM&V plan must also specify the name and Web address of the technical reference manual (TRM) in which all deemed electricity savings values will be documente d. Prior to use in an EM&V plan, all TRMs must undergo a review process in which the public, stakeholders, and experts are invited

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

– to provide comment, have at least 2 months t o provide comment, and in which all such comments and associated responses are made publicly available. All TRMs must also be publicly accessible over the full period of time in which they are being used in conjunction with an EM&V plan for the purpose of quantifying savings, and must be subsequently updated in the same manner at least every 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 app lied (including the climate zone, building type, manner of implementation, applicable end uses, operating conditions, and effective useful life), and the manner in which the electricitysavings value was quantified, which must include applicable engineerin g algorithms, source documentation, specific assumptions, and other relevant data to support the quantification of savings from the subject EE technology or

measure. (v) All EE programs and projects must be quantified at time intervals (in years) sufficien t 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 characterist ics of the specific EE program or project, expected variability in electricity savings (where greater variability necessitates more frequent quantification), the expected scale and magnitude of the electricity savings (where greater quantities of savings n ecessitate more frequent quantification), and the experience implementing and quantifying savings from the resource (where less experience

– for example, with new and innovative 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 project, 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 project, as relevant for the type of program or project and factors listed in §62.16455(7)(v) above. (C) Annually for commercial and industrial projects, unless the resource provider can provide a reasonable justification in

t he EM&V plan for why an annual time interval is not feasible, and can additionally explain how the accuracy and reliability of savings values will not be lessened. (vi) EM&V plans must specify and document how the following EM&V components will be analyzed , considered, or otherwise addressed in the quantification and verification of electricity savings: (A) The effects of changes in independent factors on reported electricity savings (i.e., factors that are not directly related to the EE measure, such as w eather, occupancy, and production levels. (B) The effective useful life (EUL) or duration of time the EE measure is anticipated to remain in place and operable with the potential to save electricity, which must be based on the application of EM&V methods, an industry best

- practice persistence study, deemed estimates of effective useful life, or a combination of all three. ( 1 ) If deemed estimates of effective useful life are used, then they must specify the date by which the EE measure will stop saving el ectricity.( 2 ) If industry best

- practices persistence studies are used to modify an effective

- useful

- life value, then they must be conducted at least every 5 years. (C) The potential sources of double counting, and the associated steps for avoiding and correcting for it, such as: ( 1 ) For programs and projects with identified participants, track the type and number of EE measures implemented at the utility

- customer level. ( 2 ) For programs without identified participants, such as point

- of

- sale rebate s and retailer or manufacturer incentive programs, track applicable vendor, retailer, and manufacturer data. ( 3 ) For programs and individual EE projects (such as those implemented by an energy service company) that both have identified participants, use tracking data to avoid and correct for double counting that may occur across the two. ( 4 ) For programs with identified participants and those without (such as retail incentives to purchase energy

- efficient equipment), use program tracking data for the f ormer 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 savings verification approaches for ensuring that EE equipment has been properly installed, is o perating asintended, and therefore has the potential to save electricity, including how verification will be carried out within the first year of implementation of the EE program or project using best

practice approaches, such as physical inspections at a customer premises, phone and mail surveys, and reviews of sales receipts and other documentation (as described in the EM&V guidance issued by the Administrator). (E) The interactive effects of EE measures on electricity usage, which are increases or dec reases 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, project, or measure (e.g., lighting retrofits to improve EE can reduce waste heat to the surrounding conditioned space, and therefore may increase the required electric heating load in a facility or premises). (vii) The EM&V plan must specify how the accuracy and reliability of the electricity savings of the EE program or project will be asse ssed, and must discuss the rigor of the method selected to quantify the electricity savings. It must also discuss the approaches that will be used to control all relevant types of bias and to minimize the potential for systematic and random error, as well as the program

- or project

specific circumstances in which such bias and error are likely to arise. Approaches to minimizing bias and error are discussedin the EM&V guidance issued by the Administrator. (viii) If sampling will be used to quantify the ele ctricity savings from an EE program, then the MWh estimates derived from sampling must have at least 90 percent confidence intervals whose end points are no more than +/

- 10 percent of the estimate, and the statistical precision of the associated estimates must be specified in the EM&V plan. (ix) All data sources and key assumptions used to quantify electricity savings must be described in the EM&V plan. (x) Any additional information necessary to demonstrate that the electricity savings were appropriatel y quantified and verified. Considerations for quantifying and verifying savings from several EE activities are described in the EM&V guidance provided by the Administrator. (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 prima ry 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 info rmation oromitting required statements and information, including the possibility of fine or imprisonment.” **(2) [Reserved] §**  **§ 62.16265 What are the requirements for monitoring and**  **verification reports for eligible resources?** (a) M&V report requirements. Any M&V report that is submitted, in support of the issuance of a set

- aside allowance that can be used in accordance with § 62.16240, must meet t he requirements of this section. (b) General M&V report criteria. Each M&V report must include the information i n paragraphs (b)(1) and (2) of this section. (1 ) For the first M& V report submitted, documentation that the electricity

- generating resources, electricity

- saving measures, or practices were installed or implemented consistent with the description in the approved eligibility application required in § 62 .16245(a)(3). ( 2 ) Fo r 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 period 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&V report, q uantified 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 re source 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 disclo sure 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 capabil ity 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 report submitted pursuant to this subpart includes the following certification: (1) “ I certify under penalty of law that I have personallyexamined, 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 f or submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment. ” **(2) [Reserved] §62.16270**  **What are the requirements for verification reports?** (a) A verification report incl uded 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 inc lude 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

ve rification report, including an assessment of whether the eligibility application or M&V report contains any material misstatements or material data discrepancies, and whether thesubmittal 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 o f law that I have personally exa mined, 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] (b) A verification report included as part of an eligibility application must, at a minimum, describe the review conducted by the accredited independent verifier and verify each of the following: (1) The eligibility of the eligible resource to be issued

set

- aside allowances pursuant to this regulation, in accordance with § 62 .16245 ( a), including an analysis of the adequacy andvalidity of the information submitted b y the authorized account

represen tative to demonstrate that the eligible resource meets each applicable requirement of § 62.16245 ; (2) The eligible resource is not duplicative of a resource used to meet emission standards or a state measure in another approved 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 § 62.16260 ; (5) Disclosure of any mandatory or voluntary programs to which data is reported relating to the eligible resource (e.g., reporting of electric generation by a renewable energy resource to a renewable energy certificate tracking system) ; and (6) Any other information required by the Administrator or that the acc redited 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 n M&V report must, at a minimum, describe the review conducted by the accredited independent verifier and verify the information specified in paragraphs (c)(1) through (3) of this section.(1) The adequacy and validity of the information and data submitted in the submittal by the authorized account representative to quantify eligible MWh of electric generation or electricity savings during the period for which the authorized account representative seeks issuance of set

- aside allowances, as well as all supporting information and data identified in the EM&V plan and M&V report. This analysis must include a quality assurance and quality control check of the data and ensure that all generation or savings data is within a technically feasible range for that specific eligible resou rce. (i) For metered generation, the data validity check must compare reported electricity generation to an engineering estimate of the maximum generation potential of the qualified renewable energy resource, based on, at a minimum, its maximum nameplate c apacity in MW and the number of days since the prior cumulative meter reading was entered in the allowance tracking system. If the data entered exceeds the estimated technically feasible generation, then the reported data and the estimate must be analyzed in the verification report. (ii) For all electricity generated or saved, the accredited independent verifier must describe the likely source of any data discrepancy and determine in the verification report any MWh generated or saved. (2) The M&V report me ets the requirements of § 62.16265

.(3) Any other information required by the Administrator or that the accredited independent verifier finds, in its professional opinion, is necessary to assess the adequacy and validity of information and data supplied by the authorized account representative. **§ §62**  **.16275 What is the accreditation procedure for independent**  **verifiers?** (a) Only Administrator

- accredited independent verifiers may provide a verification report for an eligibility application or M&V report. (b) Applications for accreditation must follow a procedure and form specified by the Administrator which shall include a demonstration by the verifier that it meets the requirements in paragraph ( c ) of this section

. ( c ) Independent verifiers must meet each of the requirements in paragraphs ( c )(1) through (6) of this section to be accredited. (1) Independent verifiers must have the skills, experience, resources (personnel and otherwise) to provide verification reports, including the following: (A) Appropriate technical qualification (professional engineer or otherwise) to evaluate the eligible resource for which the independent verifier is seeking accreditation, whichmay 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) K nowledge of the requirements of the Administrator’s CO 2 Rate

- based Trading Program regulations and related guidance ; (D) Knowledge of the eligible resource categories for which the independent verifier is seeking accreditation, including relevant aspects of the design, operation, and related energy generation or electricity savings monitoring and reporting approaches for such eligible resources ; and (E) Capability to perform key verification activities, such as development of a verification report; site v isits; review and recalculation of reported data; review of data management systems; review of quantification methods used in accordance with an approved EM&V plan; preparation of a verification opinion, list of findings, and verification report; and inter nal 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 personneland any contracto rs or subcontractors (collectively, accredited independent verification team) and demonstrate that they meet the requirements of paragraph (c)(1) of this section . Once accredited, only the accredited independent verification team identified in the accredit ation application and accredited by the 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 verif ication services related to an eligible resource category for which it is accredited. (4) Prospective independent verifiers must meet the requirements of **§** 62.16280(d) through (f) and demonstrate that they have in place adequate systems and protocols to id entify, disclose and avoid potential conflicts of interest. (5) An accredited independent verifier must not be debarred, suspended, or proposed for debarment pursuant to the
Government

- wide Debarment and Suspension regulations, 40 CFR part 32, or the Debar ment, Suspension and Ineligibility provisions of the Federal Acquisition Regulations, 48 CFR part 9, subpart 9.4. (6) An accredited independent verifier must maintain, for its employees, and ensure the maintenance of, for any parties that it employs, professional liability insurance, as defined in31 C.F.R. 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 & Po or’s, and Aaa, Aa, A, or Baa for Moody’s. Any entity covered by this paragraph shall disclose the level of professional liability insurance they possess when entering into contracts to provide verification services pursuant to thi s regulation. ( d ) Requirem ents for maintenance of accreditation status. (1) Accredited independent verifiers must meet the requirements of **§** 62.16280 when providing verification services for a n authorized account representative. (2) The instances specified in section 62.16280(d) a re cause for revocation of a verifier’s accreditation. **§ 62.16280 What are the procedures accredited independent**  **verifiers must follow to avoid conflict of interest?** (a) Accredited independent verifiers must not provide verification services for any eligible resource for which it has a conflict of interest ( COI ) , which means: (1) Accredited independent verifiers must have, or have had, no direct or indirect financial interest in, or other financial relationships with, an eligible resource, or any prospective eligible resource, for which the y seek to provide a verification report ;(2) Accredited independent verifiers must have, or have had, no direct or indirect organiz ational 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 hav e had, no role in the development and implementation of an eligible resource for which a n authorized account representative seeks issuance of set

- aside allowances, beyond the provision of verification services ; (4) Accredited independent verifiers must no t be compensated, financially or otherwise, directly or indirectly, on the basis of the content of its verification report (including eligibility approval of an eligible resource, the quantified and verified MWh in an M&V report, set

- aside allowance issuan ce, or the number of set

- aside allowances issued) ; (5) Accredited independent verifiers must not own, buy, sell, or hold set

- aside allowances, or other financial derivatives related to set

- aside allowances, or have a financial relationship with other par ties that own, buy, sell, or hold

set

- aside allowances or other related financial derivatives ;(6) An accredited independent verifier must not be incapable of providing an impartial verification report for any other reason ; and (7) An accredited independe nt 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 an y drafts of its reports with the Administrator at the same time as it shares them with the subject of the report. (b) A contract with an eligible resource for the provision of verification services shall not constitute a COI
. (c) Verification reports must include an attestation by the accredited independent verifier that it evaluated and disclosed to the Administrator any potential COI related to an eligible resource. (d) Prior to engaging for the provision of verification

ser vices, an accredited independent verifier must demonstrate that it has no COI related to the eligible resource, as specified in paragraph (a) of this section . If a COI is identified for a person or persons within an accredited independent verifier for a sp ecific subject or verification, in accordance with paragraphs (e) and (f) of this section , then an accredited independent verifier may propose to the Administratorsteps that will be taken to eliminate the 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 t he person(s) conducting the verification services. In no instance shall an accredited independent verifier engage in verification services for an eligible resource without the approval of the Administrator. (e) Prior to engaging in verification services an d writing a verification report, an accredited independent verifier shall disclose to the Administrator all information necessary for the Administrator to evaluate a potential COI (including information concerning its ownership, past and current clients, r elated entities, as well as any other facts or circumstances that have the potential to create a COI ). (f) Accredited verifiers shall have an ongoing obligation to disclose to the Administrator any facts or circumstances that may give rise to a COI as def ined in paragraph (a) of this section

. (g) The Administrator may reject a verification report from an accredited independent verifier, if the Administrator determines that the accredited independent verifier has a COI as defined in paragraph (a) of this s ection . If the Administratorrejects an accredited independent verifier report for such

reasons, then the eligibility application or M&V report submittal must be deemed incomplete and set

- aside allowances must not be issued pursuant to it. **§62.16285 What**  **is the process for the revocation of accreditation status for an independent verifier?**  (a) The Administrator may revoke the accreditation of an independent verifier at any time for cause, including for the reasons specified in paragraphs (a)(1) through (4) of this section

. (1) Failure to fully disclose any issues that may lead to a
COI with respect to an eligible resource, or other related entity, in accordance with § 62.16280(d) through (f). (2) The accredited independent verifier is no longer qualified t o 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

rep ort. **Designated Representatives §62.16290**  **How are designated representatives and alternate designated representatives authorized? What role do authorized** **designated representatives and alternate designated representatives play?**  (a) Except as provided under §62.16300, each facility, including all affected EGUs at the facility, shall have one and only one designated representative, with regard to all matters under the 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 act in accordance with the certification statement in §62.16305(a)(4)(iii). (2) Upon and after receipt by the Administrator of a complete certi ficate of representation under §62.16305: (i) The designated representative shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of the facility and each affect ed 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 owners and operators; and (ii) The owners and operators of the facility and each affected E GU 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 f acility may have one and only one alterna te designated representative, who may act on behalf of the designated representative. The agreement by which the alternate designated representative is selected shall include a procedure for authorizing the alternate designated representative to act in lie u 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 act in accordance with the certification s tatement 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 be authorized; (ii) Any representation, action, inaction, or s ubmission by the alternate designated representative shall be deemed to be a representation, action, inaction, or submission by the designated representative; and (iii) The owners and operators of the facility and each affected EGU at the facility shall be bound by any decision or order issued to the alternate designated representative by the Administrator regarding the facility or any such affected EGU.(c) Except in this section, §62.16375, and §§62.16295 through 62.16315, whenever the term “designated re presentative” (as distinguished from the term “common designated representative”) is used in this subpart, the term shall be construed to include the designated representative or any alternate designated representative. **§62.16295 What responsibilities do d**  **esignated representatives and alternate designated representatives hold?**  (a) Except as provided under §62.16315 concerning delegation of authority to make submissions, each submission under the CO 2 Mass

- based Trading Program shall be made, signed, and cert ified by the designated representative or alternate designated representative for each f acility and affected EGU for which the submission is made. Each such submission shall 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 fa miliar 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 bes t of my knowledge andbelief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.” (b) The Administrator will accept or act on a submission made for a 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 and**  **operators, and affected EGUs at the facility?** (a) Changing designated representative **.** The designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under §62.16305. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous designated representative before the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new designated representative and the owners and operators of the f acility and the affect ed 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 completecertificate of representation under §62.16305. Notwith standing any such change, all representations, actions, inactions, and submissions by the previous alternate designated representative before the time and date when the Administrator receives the superseding certificate of representation shall be binding o n the new alternate designated representative, the designated representative, and the owners and operators of the 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 representati ons, actions, inactions, and submissions of the designated representative and any alternate designated representative of the facility or affected EGU, and the decisions and orders of the Administrator, as if the owner or operator were included in such list

. (2) Within 30 days after any change in the owners and operators of a facility or an affected EGU at the facility, including the addition or removal of an owner or operator, the designated representative or any alternate designated representative shall su bmit a revision to the certificate ofrepresentation 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 facilit y (including the addition or removal of an affected EGU), the designated representative or any alternate designated representative shall submit a certificate of representation under §62.16305 amending the list of affected EGUs to reflect the change. (1) If the change is the addition of an affected EGU that operated (other than for purposes of testing by the manufacturer before initial installation) before being located at the facility, then the certificate of representation shall identify, in a format presc ribed 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 th e 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 identify, in a format prescribed by the Administrator, the entity to which the affected EGU w as sold or that otherwise obtained the affected EGU (including name, address, telephone number, email addressand facsimile number (if any)), the date on which the affected EGU was sold or otherwise obtained, and the date on which the affected EGU became no longer located at the facility. **§62.16305 What must be included in a certificate of**  **representation?** (a) A complete certificate of representation for a designated representative or an alternate designated representative shall include the following elemen ts in a format prescribed by the Administrator: (1) Identification of the facility, and each affected EGU at the facility, for which the certificate of representation is submitted, including facility and affected EGU names, facility category and NAICS code (or, in the absence of a NAICS code, an equivalent code), State, plant code, county, latitude and longitude, unit identification number and type, identification number and nameplate capacity (in MWe, rounded to the nearest tenth) of each generator served by each such affected EGU, actual or projected date of commencement of commercial operation, 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 dat e of commencement of commercial operation shall be provided when such information becomes available.(2) The name, address, email address (if any), telephone number, and facsimile transmission number (if any) of the designated representative and any altern ate designated representative. (3) A list of the owners and operators of the facility and of each affected EGU at the facility. (4) The following certification statements by the designated representative and any alternate designated representative : (i) “I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators of the facility and each affected EGU at the facility” ; and (ii) “I certify that I have all the necessary authority to carry out my duties and responsibilities under the 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 decision or order issued to me by the Administrator regarding the facility or unit.” (iii) “Where there are multiple holders of a legal or equitable title to, or a leasehold i nterest in, an affected EGU, or where a utility or industrial customer purchases power froman 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 repre sentative’ or ‘alternate designated representative’, as applicable, and of the agreement by which I was selected to each owner and operator of the facility and of each affected EGU at the facility; and CO 2 allowances and proceeds of transactions involving CO 2 Mass

- based Trading allowances will be deemed to be held or distributed in proportion to each holder's legal, equitable, leasehold, or contractual reservation or entitlement, except that, if such multiple holders have expressly provided for a different distribution of CO 2 allowances by contract, then CO 2 allowances and proceeds of transactions 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 otherwise required by the Administrator, documents of agreement referred to in the certificate of representation shall not be submitted to the Administrator. The Ad ministrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.**§62.16310 What is the Administrator’s role in objections**  **concerning designated representatives and alternate designated representatives?**  ( a) Once a complete certificate of representation under §62.16305 has been submitted and received, the Administrator will rely on the certificate of representation unless and until a superseding complete certificate of representation under §62.16305 is rece ived 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 rep resentative or alternate designated representative shall affect any representation, action, inaction, or submission of the designated representative or alternate designated representative or the finality of any decision or order by the Administrator under the CO 2 Mass

- based Trading Program. (c) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any designated representative or alternate designated representat ive, 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 ma y delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart. (b) An alternate designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart. (c) In order to delegate authority to a natural person to make an electronic submission to the Administrator in accordance with paragraph ( a) or (b) of this section, the designated representative or alternate designated representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the elements in paragraphs (c)(1) through (4) of this section. (1) The name, address, 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, telepho ne 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 sectio n for which authority is delegated to him or her

. (4) The following certification statements by such designated representative or alternate designated representative: (i) “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 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 immediately 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 sectio n shall be effective, with regard to the designated representative or alternate designated representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegati on submitted by such designated representative or alternate designated representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority. (e) Any electronic submission covered by the certification in paragraph (c)(4)(i) of this section and made in accordance with a notice of delegation effective under paragraph (d) of this section shall be deemed to be an electronic submission by the designated representative or alternate designated representative submitting such notice of delegation. **Monitoring, Recordkeeping, Reporting §62.16320**  **How are compliance accounts and general accounts established?**  (a) Compliance accounts **.** Upon receipt of a complete certificate of representation under §62.16305, the Administrator will establish a compliance account for the facility for which the certificate of representation was submitted, unless the facility already has a compliance account. The designatedrepresenta tive 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 a ccount s **.** (1) A retirement account, i nto which allowances held in a compliance account for an affected EGU are surrendered by the owner or operator of an affected EGU, for use in demonstrating compliance with its emission standards. The retirement account may only be held by the Administrator , and allowances deposited into it are permanently retired. Once an allowance is retired, the allowance shall no longer be transferable to another account in that allowance tracking system or any other allowance tracking system. **(2) [Reserved]** (c) General accounts **.** (1) Application for a general

account . (i) Any person may apply to open a general account, for the purpose of holding and transferring CO 2 allowances, by submitting to the Administrator a complete application for a general account. Such applicati on shall 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 a nd alternate authorized account representative shall be selected by anagreement binding on the persons who have an ownership interest with respect to CO 2 allowances held in the general account. (B) The agreement by which the alternate authorized account

r epresentative is selected shall 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 include the following eleme nts in a format prescribed by the Administrator: (A) Name, mailing address, e

- mail address (if any), telephone number, and facsimile transmission number (if any) of the authorized account representative and any alternate authorized account representative; (B) An identifying name for the general account; (C) A list of all persons subject to a binding agreement for the authorized account representative and any alternate authorized account representativ e to represent their ownership interest with respect to th e 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 bindingon all persons who have an ownership interest 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 r epresentations, 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 representa tive and the dates signed. (iii) Unless otherwise required by the Administrator, documents of agreement referred to in the application for a general account shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted. (2) Authorization of authorized account representative and alternate authorized account representative . (i) Upon receipt by the Administrator of a complete application for a general

accou nt under paragraph ( c )(1) of this section, the Administrator will establish a general account for the person or persons for whom the application is submitted, and upon and after such receipt by the Administrator:(A) The authorized account representative of the general account shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each person who has an ownership interest with respect to
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 submission 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 alternate authorized account representative by the Administrator regarding the general account. (ii) Except as provided i n paragraph ( c )(5) of this section concerning delegation of authority to make submissions, each submission concerning the general account shall be made, signed, and certified by the authorized account representative or any alternate authorized account representative for the persons having an ownership interest with respect to CO 2 allowances heldin the general account. Each such submission shall include the following certification statement by the authorized account representative or any alternate autho rized account representative: “I am authorized to make this submission on behalf of the persons having an ownership interest with respect to the CO 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 with primary responsibility for obtaining the information, I certify that the statements and information are

to t he 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 imprisonm ent.” (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 timeupon receipt by the Administrator of a superseding complete application for a general account under paragraph ( c )(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new authorized account representative and the persons with an ownership interest with respect to the 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 superseding complete application for a general account under paragraph (c)(1) of this section. Notwithstanding any such c hange, all representations, actions, inactions, and submissions by the previous alternate authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the n ew 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 re spect to CO 2 allowances in the general account is not included in the list of such persons in the application for ageneral account, such person shall be deemed to be subject to and bound by the application for a general account, the representation, action s, inactions, and submissions of the authorized account representative and any alternate authorized account representative of the account, and the decisions and orders of the Administrator, as if the person were included in such list. (B) Within 30 days af ter any change in the persons having an ownership interest with respect to CO 2 allowances in the general account, including the addition or removal of a person, the authorized account representative or any alternate authorized account representative shall submit a revision to the 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 representativ e and alternate authorized account representative

. (i) Once a complete application for a general account under paragraph (c)(1) of this section has been submitted and received, the Administrator will rely on the application unless and until a superseding complete application for a general account under paragraph ( c )(1) of this section is received by the Administrator.(ii) Except as provided in paragraph ( c )(4)(i) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account shall affect any representation, action, inaction, or subm ission 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 priva te legal dispute concerning the authorization or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account, including private legal disputes concerni ng 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 natural person to make an electronic submission to the Administrator in accordance with paragraph ( c )(5)(i) or (ii ) of this section, the authorized account representative or alternate authorized account representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following eleme nts: (A) The name, address, e

- mail address, telephone number, and facsimile transmission number (if any) of such authorized account representative or alternate authorized account representative; (B) The name, address, e

- mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to in this section as an “agent”); (C) For each such natural person, a list of the type or types of electronic submissions under paragraph ( c )(5)(i) or (ii) of this section for wh ich authority is delegated to him or her; (D) The following certification statement by such authorized account representative or alternate authorizedaccount representative: “I agree that any electronic submission to the Administrator that is made by an ag ent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am an authorized account representative or alternate authorized representative, as appropriate, and before this notice of d elegation is superseded by another notice of delegation under 40 CFR 62.16320( c )(5)(iv) shall be deemed to be an electronic submission by me”; and (E) The following certification statement by such authorized account representative or alternate authorized

a ccount representative: “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 62.16320( c )(5)(iv), I agree to maintain an e

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

- mail address unle ss all delegation of authority by me under 40 CFR 62.16320(c)(5) is terminated.” (iv) A notice of delegation submitted under paragraph ( c )(5)(iii) of this section shall be effective, with regard to the authorized account representative or alternate authori zed 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 authorizedaccount 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 para graph ( 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 representat ive 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 requ est shall include a correctly submitted CO 2 allowance transfer under §62.16330 for any CO 2 allowances in the account to one or more other Allowance 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 Administrator receives a correctly submitted CO 2 allowance transfer under §62.16330 tothe account or a statement submitted by the authorized account representa tive or alternate authorized account representative demonstrating to the satisfaction of the Administrator good cause as to why the account should not be closed. (d) Account identification **.** The Administrator will assign a unique identifying number to each account established under paragraphs (a) through (c) of this section. (e) Responsibilities of authorized account representative and alternate authorized account r epresentative **.** After the establishment of a compliance account or general account, the Adminis trator will accept or act on a submission pertaining to the account, including, but not limited to, submissions concerning the deduction or transfer of CO 2 allowances in the account, only if the submission has been made, signed, and certified in accordance with §§62.16295(a) and 62.16315 or paragraphs (c)(2)(ii) and (c)(5) of this section. **§62.16325 When will 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 UUU U of part 60 of this chapter, for the upcoming compliance period. (b) Except as specified in paragraph (a) of this section, the Administrator will record an allocation in the appropriate Allowance Tracking and Compliance System account by the date on which any allocation of CO 2 allowances to a recipient must be made by or submitted to the Administrator in accordance with either § §62.16240 or with state allowance

- distribution methodology approved under subpart UUUU of part 60 of this chapter. (c) When recording the allocation of CO 2 allowances to an affected EGU or other entity in an Allowance 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 thereafter, the Administrator will record in each renewable energy project’s general account, the CO 2 allowances all ocated from the renewable energy set

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

- based set

aside to the eligible EGUs at the facility in accordance with §62.16245(b) or with a state 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 submit the transfer to the Administrator. (b) A CO 2 allowance transfer shall 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 account s; (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 signature of the authorized account representative of the transferor account and the date signed; and (2) When the Administra tor 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 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 transfer deadline for a compliance period and that includes any
CO 2 allowance s 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 allowan ce 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 5 business days of 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 allowance transfer that is not correctly submitted under §62.16330, theAdministra tor will notify the authorized account representatives of both accounts subject to the transfer of: (1) A decision not to record the transfer ; and (2) The reasons for such non

- recordation. **§62.16340 How will deductions for compliance with a**  **CO 2**  **emission**

**st andard occur?**  (a) Availability 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: (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 C O 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 available under paragraph (a) of this section in order to determine whether th e 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 from 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 remain 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 account be deducted for emissions or excess emissions for a compliance period in accordance with paragraph (b) or (d) of this section. In order to be complete, such request shall be submitted to the Administrator by the allowance transfer deadline for such compliance period and include, in a format prescribed by the Administrator, t he identification of the 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

requ est 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) Deductions for excess emissions **.** After making the deductions for compliance under paragraph (b) of this section for a compliance period in a year in which th e facility has excess emissions, the Administrator will deduct from the facility's compliance account 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 imme diately 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) an d (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 emissionsto be monitored and reported according to part 75 of this chapter. You must follow the requirements described in paragraphs (a)(1) through (8) of this section to monitor emissions and net energy output at your affected EGU. (1) For each operating hour, calculate the hourly CO 2 mass (tons) according to paragraph (a)(4) or ( 5) of this section, except that a complete data record is required, i.e., CO 2 mass emissions must be r eported 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/or GCV shall be used in the calculations; and (2) Sum all o f 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 suffic ient 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, ifapplicable, mechanical output, which are used with net electric output to determine net ener gy 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 affect ed unit using the procedures in paragraphs (a)(4)(i) through (vi) of this section, except as otherwise provided in paragraph (a)(5) of this section. (i) The owner or operator of an affected EGU must install, certify, operate, maintain, and calibrate a 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 additional 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 storage), the owner or operator of an affected EGU may use data from a certifiedoxygen (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 the owner or operator of the affecte d 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 operat or 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/or GCV shall be used in the calcul ations

. (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 resultby 2000 lb/ton to convert it to lb. (iv) The hourly CO 2 to ns/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 t hese data, or equivalent data, to calculate the hourly CO 2 mass emissions. (v) Sum all of the hourly CO 2 mass emissions values that were calculated according to procedures specified in paragraph (a)(4)(ii) of this section over the entire compliance period

. (vi) For each continuous monitoring system used to determine the 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 cha pter and Appendices A and B to part 75 of this chapter. (5) The owner or operator of an affected EGU that exclusively combusts liquid fuel and/or gaseous fuel may, as an alternative to complying with paragraph (a)( 4 ) of this section, determine the hourly CO 2 mass emissions according to paragraphs (a)(5)(i) through (vi) of this section. (i) Implement the applicable procedures in appendix D to part 75 of this chapter to determine hourly EGU heat input rates (MMBtu/h), based on hourly measurements of fuel flow rate and periodic determinations of the gross calorific value (GCV) ofeach fuel combusted. The fuel flow meter(s) used to measure the hourly fuel flow rates must meet the applicable certification and quality

- assurance requirements in sections 2.1.5 and 2. 1.6 of appendix D (except for qualifying commercial billing meters). The fuel GCV must be determined in accordance with section 2.2 or 2.3 of appendix D, as applicable. (ii) For each measured hourly heat input rate, use Equation
G

- 4 in Appendix G to part 7 5 of this chapter to calculate the hourly CO 2 mass emission rate (tons/hr). (iii) Determine the hourly CO 2 mass emission rate (tons/hr) using the procedures specified in paragraph (a)(4)(ii) of this section and multiply it by the EGU or stack operating ti me in hours (as defined in §72.2 of this chapter), to convert to tons of CO 2 . Then, multiply the result by 2000 lb/ton to convert to lb. (iv) The hourly CO 2 tons/hr values and EGU (or stack) operating times used to calculate CO 2 mass emissions are require d to be recorded under §75.57(e) of this chapter and must be reported electronically under §75.64(a)(6), if required by a plan. You must use these data, or equivalent data, to calculate the hourly CO 2 mass emissions. (v) Sum all of the hourly CO 2 mass emi ssions values (lb) that were calculated according to procedures specified inparagraph (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 ) usin g 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 Equation G

- 4 nomenclature. (6) The owner or operator of an affected EGU must install, calibrate, maintain, and operate a sufficient number of watt meters to continuously measure and record on an hourly basis net electric output. Measurements must be performed using 0.2 accuracy class electricity metering instrumentation and calibra tion 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 hour ly basis useful thermal output and, if applicable, mechanical output, which are used with net electric output to determine net energy output. The owner or operator must calculate net energy output according to paragraph (a)(6)(i) of this section. (i) For e ach operating hour of a compliance period that was used in paragraph (a)( 4 ) or (5) of this section to calculate the total CO 2 mass emissions, you must determine P net (thecorresponding hourly net energy output in MWh) according to the procedures in paragraphs (a)( 6 )(i)(A) and (B) of this section, as appropriate for the type of affected EGU(s). For an operating hour in which a valid CO 2 mass emissions value is determined according to paragraph (a)( 4 ) or (5) of this section, if there is no gross or net electrical output, but there is mechanical or useful thermal output, you must still determine the net energy output for that hour. In addition, for an operating hour in which a valid CO 2 mass emissions value is determined according to paragraph (a)( 4 ) or (5) of this section, but there is no (i.e., zero) gross electrical, mechanical, or useful thermal output, you must use that hour in the compliance determination. For hours or partial hours where the gross electric output is equal to or less than the auxili ary 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 must be expressed in units of megawatt

- hours (MWh). To convert each hourly net en ergy 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 ) AA TDF + [ ( PPPP ) PP + ( PPPP ) HHHH + ( PPPP ) IIII ]

Where: a

P net = Net energy output of your af fected EGU in MWh.(Pe) ST = Electric energy output plus mechanical energy output (if any) of steam turbines in MWh. (Pe) CT = Electric energy output plus mechanical energy output (if any) of stationary combustion turbine(s) in MWh. (Pe) IE = Electric energy output plus mechanical energy output (if any) of your affected EGU’s integrated equipment that provides electricity or mechanical energy to the affected EGU or auxiliary equipment in MWh. (Pe) A = Electric energy used for any auxiliary loads in MWh. (Pt) PS = Useful thermal output of steam (measured relative to SATP conditions, as applicable) that is used for applications that do not generate additional electricity, produce mechanical energy output, or enhance the performance of the affected EGU. This is cal culated using the equation specified in paragraph (a)( 6 )(i) (B) of this section in MWh. (Pt) HR = Non steam useful thermal output (measured relative to SATP conditions, as applicable) from heat recovery that is used for applications other than steam generati on 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 mechani cal energy output, or enhance the performance of the affected EGU in MWh.

TDF = Electric Transmission and Distribution Factor of 0.95 for a combined heat and power affected EGU where at least on an annual basis 20.0 percent of the total net energy output consists of electric or direct mechanical output and 20.0 percent of the total net energy output consists of useful thermal output on a 12

- operating month rolling average basis, or 1.0 for all other affected
EGUs.

(B) If applicable to your affected EGU (f or 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 usedfor 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 tempe rature 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. (ii) [Reserved] (7) In accordance with §60.13(g), if two or more affected EGUs implementing the continuous emissio ns 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 mon itor 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 of the hourly net ele ctric 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 continu ous emissions monitoring provisions in paragraph (a)( 3 ) of this section are emitted to the atmosphere through multiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you elect to monitor in the ducts), the hourly 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 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 account u nless and until the CO 2 allowance is deducted or transferred under §62.16240(b), §62.16335, §62.16340, 62.16355, or 62.16370. **§62.16355 How does the Administrator process account errors?** The Administrator may, at his or her sole discretion and on his or h er own motion, correct any error in any Allowance Tracking and Compliance System account. Within 10 business days of making such correction, the Administrator will notify the authorized account representative for the account. **§62.16360 What are my reportin**  **g, notification and submission requirements?**  (a) You must prepare and submit reports according to paragraphs (a) through (d ) 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) and unit (or stack) operating time, as monitored and reported according to pa rt 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 compliance period; (iii) The sum of the CO 2 mass emissions (tons) for all of

t he 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 compliance period;(v) The sum of the hourly net energy output values for all of the unit or stack operating hours in the compliance period ; and ( vi ) If the report covers the final quarter or a compliance period , then you must include the CO 2 emission standard with which your affected EGU must comply, the affected EGUs calculated emission performance as a cumulative mass in units of the emission standard required, and if an affected EGU is complying with an emission standard by using 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 set

- aside allowances were used from an eligible resource by an affected EGU to comply with its emission standard, then the designated representative must include in their report the eligible resource identification information sufficient to demonstrates that it meets the requirements o f §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 repres entative of each affected EGU at the facility shall make all submissions required under the CO 2Mass

- based Trading Program, except as provided in §62.16315. This requirement does not change, create an exemption from, or otherwise affect the responsible off icial submission requirements under a title V operating permit program in parts 70 and 71 of this chapter. (c) You must submit all electronic reports required under paragraph (a) of this section using the Emissions Collection and Monitoring Plan System (EC MPS) Client Tool provided by the Clean Air Markets Division in the Office of Atmospheric Programs of

EPA. (d) For affected EGUs under this subpart that are not in the Acid Rain Program, you must also meet the reporting requirements and submit reports as required under subpart G of part 75 of this chapter, to the extent that those requirements and reports provide applicable data for the compliance demonstrations required under this subpart. (e) If your affected EGU captures CO 2 to meet the applicable emission standard, then you must report in accordance with the requirements of 40 CFR Part 98 Subpart PP and either: (1) Report in accordance with the requirements of 40 CFR Part 98 subpart RR, if injection occurs on

- site; or (2) Tr ansfer the captured CO 2 to an EGU or facility that reports in accordance with the requirements of 40 CFR p art 98 subpart RR, if injection occurs off site.(f) You must prepare and submit notifications specified in
§ 75.61 of this chapter, as applicable to y our affected EGUs. **§62.16365 What are my recordkeeping requirements?**  (a) The owner or operator of each affected EGU must maintain the records, as described in paragraphs (a)(1) and (2) of this section, for at least 5 years following the date of each

comp liance 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. The owner or operator of an affected EGU may maintain the records off site and electronically for the remaining year(s). (2) The ow ner 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, o ther submissions and all records made or required under, or to demonstrate compliance with an affected EGU’s emission standardunder § 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 75 Subpart F ; and (iv) Data with respect to any allowances used by the affected EGU in its compliance demonstration including the information in paragraphs ( a )(2)(iv)(A) and (B) of this section. (A) All documents related to any set aside allowances used in a compliance demonstration, including each eligibility application, EM&V plan, M&V report, and independent verifier verification report associated with the issuance of each specific set aside allowance, and each regulatory approval and

a ny documentation that supports the issuance of each set aside allowance by the Administrator. (B) All records and reports relating to the surrender and retirement of allowances for compliance with this regulation, including the date each individual allowan ce with a unique serial identification number was surrendered and/or retired. **§62.16370 What actions may the Administrator take on**  **submissions?** (a) The Administrator may review and conduct independent audits concerning any submission under the 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 the information in a submission, as adjuste d under paragraph (a) of this section, and record such deductions and transfers. **Definitions §62.16375**  **What definitions apply to this subpart?** The terms used in this subpart 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

En vironmental 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 under this subpart. Affected electric generating unit or Affected EGU means any steam generating unit, IGCC, or stationary combustion turbine that meets the applicability requirements in §§60.5840( b) and 60.5845 of this chapter. An affected EGU is not an eligible resource.Allocate or allocation means, with regard to 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, to: (1) An affected EGU; (2) A renewable energy set

- aside; (3) An output

- based set

- aside; or (4) An entity not listed in paragraphs (1) through (3) of this definition; Allowable CO 2 emission rate means, for an affected EGU, the most stringent 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 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 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 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 emittedfrom that faci lity during a specified period and which limits the total amount of such authorizations available to be held for carbon dioxide for a specified period and allows the transfer of such authorizations not used to meet the authorization

- holding requirement. Al lowance transfer deadline means, for a compliance period in a given year, midnight of May 1 (if it is a business day), or midnight of the first business day thereafter (if May 1 is not a business day), immediately after such compliance period and is the de adline 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 a nd 62.16340. Alternate designated representative means, for a CO 2 Mass

based Trading Program facility and each affected EGU at the facility, the natural person who is authorized by the owners and operators of the facility and all such affected EGUs at the facility, in accordance with this subpart, to act on behalf of the designated representative in matters pertaining to the 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 Trading Program, then this natural person shallbe the same natural person as the alternate designated representative, as defined in the respective program. Annual capacity factor means the ratio between the actual heat input to an affected EGU during a calendar year and the potential heat input to the affected EGU had it been operated for 8,760 hours during a calendar year at the base load rating. Also see capacity factor.

APMP me ans [specify]

. 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 and convert individual output signals from pollutant concentration monitors, flow monitors, diluent gas monitors, and other component parts of the monitoring system to produce a continuous record of the measured parameters in the measurement units required by this subpart.Base load rating means the maximum amount of heat input (fuel) that an EGU can combust on a steady state basis, as determined by the physical design and characteristics of the EGU at ISO conditions. For a stationary combustion turbine , base load rating includes the heat input from duct burners. Baseline means the electricity use that would have occurred without implementation of a specific EE measure. Biomass means biologically based material that is living or dead (e.g., trees, crops, grasses, tree litter, roots) above and below ground, and available on a renewable or recurring basis. Materials that are biologically based include non

- fossilized, biodeg radable organic material originating from modern or contemporarily grown plants, animals, or microorganisms (including plants, products, byproducts and residues from agriculture, forestry, and related activities and industries, as well as the non

- fossilize d and biodegradable organic fractions of industrial and municipal wastes, including gases and liquids recovered from the decomposition of non

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

- or other

- fuel

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

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

- or decision

- making functions for the corporation; (2) For a partnership or so le proprietorship, a general partner or the proprietor respectively; or (3) For a local government entity or 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 State or permitting authority under a state allowance

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

Based Trading Program.
CO 2 allowance deduction or deduct CO 2 allo wances 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 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 subm itted, 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 g oal means a statewide rate

- based CO 2 emission goal or mass

- based CO 2 emission goal specified in § 62. 16 235

. 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

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 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. Combined cycle unit means an electric generating unit that

uses a stationary combustion turbine from which the heat from the turbine exhaust gases is recovered by a heat recovery steam generating unit to generate additional electricity. Combined heat and power unit or CHP unit, (also known as“cogeneration”) means an electric generating unit that 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 c ontinued 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 f rom 2 or more units are exhausted. Compliance account means an Allowance Tracking and Compliance System account, established by the Administrator for
a CO 2 annual facility under this subpart, in which any CO 2 allowance allocations to the affected 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 means the multi

- year periods starting January 1 of the first calendar year of the period, except as provided in §62.16220(c)(3), and ending on December 31 of the last calendar year, inclusive: (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. (3) Compliance Period 3 means the period of two calendar years from Jan uary 1, 2028 to December 31, 2029. Continuous emission monitoring system or CEMS means the equipment required under this subpart to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes and using an automated d ata 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 applicable), in a manner consistent with part 75 of this chapter and §§62.xx30 through 62. xx35. The following systems are the principal types of continuous emission monitoring systems: (1) A flow monitoring system, consisting of a stack flow rate monitor and an automated data acquisition and handling system and providing a permanent, continuous record of stack gas volumetric flow;(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 opera tor means an electric system or systems, bounded by interconnection metering and telemetry, capable of controlling generation to maintain its interchange schedule with other control areas and contributing to frequency regulation of the interconnection. Deemed savings means estimates of average annual electricity savings for a single unit of an installed demand

side EE measure that : (a) has been developed from data sources (such as prior metering studies) and analytical methods widely considered acceptable for the measure , and (b) is a pplicable tothe 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 e nergy e fficiency or demand

– side EE means energy efficiency projects, programs or measures resulting in electricity savings.

Derate means a decrease in the available capacity of an electric generating unit, due to a system or equipment modification or to discounting a portion of a generating units capacity for planning purposes. Designated representative means, for a 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 alsosubject 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 the rmal 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 Material s 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 Test ing 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). 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. Eligible resource means a resource that meets the requirements of § 62. 16245 and has been registered with the EPA

administered ATCS or an allowance tracking system approved in a State plan by the EPA. An eligible resource is not an affected
EGU
. EM&V plan means 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, presumptively in quantities measured, recorded, and reported to the Administrator by the designated representative , and as modified by the Administrator: (1) In accordance with this subpart; and (2) With regard to a period before the affected EGU or facility is required to measure, record, and report such air pollutants in accordance with this subpart, in accordance w ith part 75 of this chapter. Emission Rate Credit or ERC means a tradable compliance instrument that meets the requirements of § 60.5790(c) of this chapter

.Essential generating characteristics means any characteristic that affects the eligibility of the qualifying energy generating facility for generating allowances pursuant to this regulation, including the type of facility. Excess emissions means any ton of emissions from the affected EGUs at a facility during a compliance period that exceeds the CO 2 em issions limitation for the facility for such compliance period. Existing state program, requirement, or measure means, in the context of a 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 or expanded in the future, in accord ance 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 adjacent proper ties 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 andimplemented in a title V operating permit program or any other program under the Clean Air Act. Final period means the period that begins on January 1, 2030 and continues thereafter. The final period is comprised of final compliance periods, each of which is two calendar years (with a calendar year beginning on Januar y 1 and ending on December 31). Final 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 beginnin g on January 1, 2030 and ending December 31, 2031. Fossil fuel means natural gas, petroleum, coal, and any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat. Fossil

- fuel

- fired means, with regard to a n 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

- o ven gas, synthetic gas, and gasified coal.General account means an Allowance Tracking and Compliance System account established under this subpart that is not a compliance account. Generation year means a calendar year for which a renewable energy project submits its projected generation to the Administrator by June 1 of the preceding year for allowances from the renewable energy set

- aside. Generation period means the compliance period from which

t he Administrator uses operations data of affected EGUs to calculate allowances from the output

- based allocation set

- aside for the following compliance period.
Generator means a device that produces electricity. Gross electrical output means, for an affect ed 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 emissi on 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

measu red, recorded, and reported to the Administrator by the designated representative and as modified by the Administratorin accordance with this subpart and excluding the heat derived from preheated combustion air, recirculated flue gases, or exhaust. Heat i nput 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 ope rating time (in hr) during which the affected EGU combusts the fuel.

Heat rate means, for an affected EGU, the affected EGU's maximum design heat input (in Btu/hr), divided by the product of 1,000,000 Btu/mmBtu and the affected EGU's maximum hourly load. Heat recovery steam generating unit (HRSG) means a unit in which hot exhaust gases from the combustion turbine engine are routed in order to extract heat from the gases and generate useful output. Heat recovery steam generating units can be used with or wi thout 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) o r more solid

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

- de rived 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 Janua ry 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 as a liquid at ISO conditions and includes, but is not limited to, distillate oil and residual oil. M&V report means a monitoring and verification report that meets the requirements of § 62.16265. Maximu m 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 th e 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 performanceof the affected facility. Mechanical energy measured in horsep ower hour should be converted into MWh by multiplying it by 745.7 then dividing by 1,000,000. Monitoring system means any monitoring system that meets the requirements of this subpart, including a continuous emission monitoring system, an alternative monit oring system, or an excepted monitoring system under part 75 of this chapter. Nameplate capacity means, starting from the initial installation of a generator, the maximum electrical generating output (in MWe, rounded to the nearest tenth) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings) as of such installation as specified by the manufacturer of the generator or, starting from the completion of any subsequent physical change in the generator resulting in an increase in the maximum electrical generating output that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other d eratings), 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 35and 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, 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.

Net

- electric output means the amount of gross generation the generator(s) produce (including, but not limited to, output from st eam turbine(s), combustion turbine(s), and gas expander(s)), as measured at the generator terminals, less the electricity used to operate the plant (i.e., auxiliary loads); such uses include fuel handling equipment, pumps, fans, pollution control equipment , other electricity needs, and transformer losses as measured at the transmission side of the step up transformer (e.g., the point of sale). Net energy output means: (1) The net electric or mechanical output from the affected facility, plus 100 percent of the useful thermal output measured relative to SATP conditions that is not used to generate additional electric or mechanical output or to enhance theperformance of the affected EGU (e.g., steam delivered to an industrial process for a heating application ) ; and (2) For combined heat and power facilities where at least 20.0 percent of the total gross or net energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross or net energy output consists of useful ther mal 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 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 operation 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 f acility respectively, any person who operates, controls, or supervises an affected EGU at the facility or the affected EGU and shall include, but not belimited to, any holding company, utility system, or plant manager of such facility or affected EGU.
Own er 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 holde r of a leasehold interest in an affected EGU at the facility or the affected EGU, provided that, unless expressly provided for in a leasehold agreement, “owner” shall not include a passive lessor, or a person who has an equitable interest through such less or, 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 facility or the affected EGU under a life

of

- the

- unit, firm power contractual arrangement. Permanently retired means, with regard to an affected EGU, an affected EGU that is unavailable for service and for which the affected EGU's owners and operators (1) have taken on as enforceable 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 n ot constitute permanent retirements

. 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. Qu alif ied biomass means a biomass feedstock that is demonstrated 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 magnitude of random error can be quantified based on the variations observed across different units. Receive or receipt of means , when referring to the Administrator, to come into possession of a document, information, or correspondence (whether sent in hard copy or by authorized electronic transmission), as indicated in an official log, or by a notation made on the document, infor mation, or correspondence, by the Administrator in the regular course of business. Recordation , record , or recorded means, with regard to CO 2 allowances, the moving of CO 2 allowances by the Administratorinto, out of, or between Allowance Tracking and Compliance System accounts, for purposes of allocation, transfer, or deduction. Reference method means any direct test method of sampling and analyzing for an air pollutant as specified in §75.22 of this chapter. Replacement , replace , or replaced means, wi th 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 re tired affected EGU (the replaced affected EGU). Solid fuel means any fuel that has a definite shape and volume, has no tendency to flow or disperse under moderate stress, and is not liquid or gaseous at ISO conditions. This includes, but is not limited to, coal, biomass, and pulverized solid fuels. Solid waste incineration unit means a stationary, fossil

fuel

- fired boiler or stationary, fossil

- fuel

- fired combustion turbine that is a “solid waste incineration unit” as defined in section 129(g)(1) of the Clea n 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 factorssuch as incorrect assumptions, a methodological issue, or a flaw ed reporting system. Standard ambient temperature 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 S tate, with the legal authority of the S tate . State measures means measures that the S tate adopts and implements as a matter of state law. Such measures are enforceable only per state law, and are not included in an d codified as part of the federally enforceable 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 eq uipment), 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 tur bine, 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 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

gen erating unit. Steam generating unit means any furnace, boiler, or other device used for combusting fuel and producing steam (nuclear steam generators are not included) plus any integrated equipment that provides electricity or useful thermal output to the affected facility or auxiliary equipment. Submit or serve means to send or transmit a document, information, or correspondence to the person specified in accordance with the applicable regulation: (1) In person; (2) By United States Postal Service; or (3) By other means of dispatch or transmission and delivery; (4) Provided that compliance with any “submission” or “service” deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt. Transmission and distributi on loss means the difference between the quantity of electricity that serves a load (measured at the busbar of the generator) and the actual electricity useat the final distribution location (measured at the on

- site meter). Unit operating day means, with regard to an affected EGU, a calendar day in which the affected EGU combusts any fuel. Unit operating hour or hour of unit operation means, with regard to an affected EGU, an hour in which the affected EGU combusts any fuel. Uprate means a n increase in ava ilable 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 applic ation, 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

energ y 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 E GU(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 distribut ion system means the portion of an electricity grid owned or operated by a utility and dedicated to delivering electricity to customers. Valid data means quality

- assured data generated by continuous monitoring systems that are installed, operated, and main tained 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 thi s chapter apply. For fuel flow meters, the initial certification requirements in section 2.1.5 of appendix D to part 75 of this chapter must be met before quality

- assured data are reported under this subpart (except for qualifying commercial billing meters under section 2.1.4.2 of appendix D), and for on

- going quality assurance, the provisions in section 2.1.6 of appendix D to part 75 of this chapter apply(except for qualifying commercial billing meters). Verification report means a report that meets the requirements of § 62.16270.

Waste

- to

- Energy means a process or unit (e.g., solid waste incineration unit) that recovers energy from the conversion or combustion of waste stream materials, such as municipal solid waste, to generate electricity and/or heat

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

ADR

- alternated designated representative

Btu

— British thermal unit
CO 2 — carbon dioxide
COI

— conflict of interest
CPP

— clean power plan

DR

- designated representative

EE

— energy efficiency
EGU

- electric generating unit

EM&V

- evaluation, measurement, and verification
GCV

- gross calorific value
GJ

- giga joule

H 2 O

— water hr

— hour kg

- kilogramkW

— kilowatt electrical kWh

— kilowa tt hour lb

— pound

M&V

– measurement and verification

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**  **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 R ate

- based Trading Program? 62.16430 What are the administrative appeal procedures? 62.16431 What is the Clean Energy Incentive Program? **Emission Rate Credit Issuance, Adjustment and Revocation** 62.16434 What affected EGUs qualify for generation of ERCs? 62.16435 What eligible resources qualify for generation of ERCs in addition to affected EGUs? 62.16440 What is the process for revocation of qualification status of an eligible resource? 62.16445 What is the process for the issuance of ERCs? 62.16450 What is the process for error adjustments or misstatement, and suspension of ERC issuance? **Evaluation Measurement and Verification Plans, Monitoring and Verification Reports, and Verification**  62.16455 What are the requirements for evaluation measurement and verification plans for eligible resources? 62.16460 What are the requirements for monitoring and verification reports for eligible resources? 62.16465 What are the requirements for verification reports? 62.16470 What is the accreditation procedure fo r independent verifiers? 62.16475 What are the procedures of accredited independent verifiers must follow to avoid conflict of interest? 62.16480 What is the process for the revocation of accreditation status for an independent verifier? **Designated Repre sentatives**  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 rep resentatives and alternate designated representatives hold? 62.16495 What are the processes for changing designated representatives, alternate designated representatives, owners and operators, and affected EGUs? 62.16500 What must be included in a certificate of representation? 62.16505 What is the Administrator’s role in objections concerning designated representatives and alternate designated representatives? 62.16510 What process must designated representatives and al ternate 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 futur e 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 s ubmissions? **Definitions** 62.16570 What definitions apply to this subpart? 62.16575 What measurements, abbreviations, and acronyms apply to this subpart?

Table 1 to Subpart NNN of Part 62

— 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 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 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 comb ined 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 s tandard for carbon dioxide (CO2). ( c ) PSD and T itle V T h resholds 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 cons idered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 51.166(b)(48) of this chapter and in any state implementation plan approved by the EPA that is interpreted to incorporate, or specifically incorporates, 4 0 CFR 51.166(b)(48) of this chapter. (2) For the purposes of 40 CFR 52.21(b)(50)(ii) of this chapter , with respect to GHG emissions from affected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 52.21(b)(49) of this chapter. (3) For the purposes of 40 CFR 70.2 of this chapter, with respect to greenhouse gas emissions from affected facilities , the “pollutant that is subject to any standard promulgated undersection 111 of 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 S tate that has incorporated by reference this subpart

as a S tate plan, or portion of a 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 S tate under part 62 of this chapter. (b) An affected EGU is any steam generating unit, IGCC, or stationary combustion turbine that meets the applicability requirements in § §60.5840(b) and 60.5845 of this chapter. **§62.16415 What are the requirements for retired affected EGUs?** (a)(1) Any affected EGU that is permanently retired as defined in § 62.16570 shall be 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 become effective on the first day of the compliance per iod immediately following the compliance period in which the retirement took effect. Within 30 days of the affected EGU's permanent retirement, the designated representative must submit a statement to the Administrator. The statement shall state, in a form at 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 sec tion shall 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 retain, at the affected EGU, records demonstrating that the affected EGU is permanently retired. The five

- 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 andoperators b ear 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 comply with the requirements of the CO 2 Rate

- based Trading Program accruing during a ny compliance periods for which the exemption is not in effect, even if such requirements must be complied with after the exemption takes effect. **General Requirements §62.16420**  **What emission standards and**  **requirements must I comply with?**  (a) Designated representative requirements. The owners and operators shall comply with the requirement to 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

req uirements. (1) The owners and operators, and the designated representative, of affected EGU shall 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 be used to determine compliance with the CO 2 emission standard under paragraph (c) of this section, providedthat, for each monitoring location from which emissions are reported, the emission rate used in determining compliance shall b e 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) Each designated representative for each affected EGU must demonstrate compliance with its emission standard listed in Table 1 of this subpart, as applicable, by calculating a CO 2 emission rate by factoring stack emissions and any emission rate credits (ERCs) into the following equation:

CCCC 2 eeeeeeeeeeeeee rrrr = ∑ MM CCCC 2 ∑ MMMM h oooo + ∑ MMMM h

W here:
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 affecte d 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) H as a unique serial number; (ii) R epresents one MWh of actual energy generated or saved with zero associat ed carbon dioxide emissions; (iii) W as issued to an eligible resource that meets the requirements of § 62.16435 or to an affected EGU that meets the requirements of §62.16434, by the Administrator through an ERC tracking system or the Allowance Tracking and Compliance System; and (iv) 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 S tate has used that same ERC for purposes of demonstrating achieve ment of its state measures. (4) As of the ERC transfer deadline for a compliance period, the owners and operators of each affected EGU must hold, in the affected EGU's compliance account, sufficient ERCs to demonstrate compliance with its applicable emissi on standardlisted in Table 1 of this subpart pursuant to the requirement of paragraph (c)(1) of this section. (5) If an affected EGU exceeds its emission standard during a compliance period, then: (i) The owners and operators of the affected EGU shall hol d ERCs required for deduction under §62.16535( e ); (ii) The owners and operators of the affected EGU are subject to federal enforcement pursuant to sections 113(a)

– (h), and section 304, of the Clean Air Act , and the United States, S tates, and other perso ns have the ability to enforce against violations (including if an affected EGU does not meet its emission standard based on its emissions, or use of ERCs that meet the compliance demonstration in §62.16420 (c)(2)) and secure appropriate corrective actions , and the owners and operators shall 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 constitute a separate violation of this subpar t 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 itmay be subject to federal enforcement pursuant to Sections 113(a)

– (h), 42 U.S.C. §§ 7413(a)

- (h), and Section 304 of the Clean Air Act, 42 U.S.C. § 7604, and the United State s, 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 su bject to federal enforcement as specified in (c)(5) (iii) of this section

. (d) Compliance periods. An affected EGU shall be subject to the requirements under paragraph (c)(1) of this section for the compliance period starting on January 1, 2022 and for each compliance period thereafter. ( 1 ) Vintage of ERCs held for compliance. An ERC held for compliance with the requirements under paragraph (c)(1) of this section for a compliance period must be an ERC that was issued for a year in such compliance period or f or a year in a prior compliance period. ( 2 ) Allowance Tracking and Compliance System (ATCS). Each ERC shall be held in, deducted from, transferred into, out of, or between ATCS accounts in accordance with this subpart. ( 3 ) Limited authorization. (i) An ERC shall only be used in accordance with the 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 the Administrator determines is necessary or appropriate to implement any provision of the Clean Air Act. ( 4 ) Property right. An ERC does not constitute a property right. (e) Title V permit requirements. (1) Unless otherwise specified in this paragraph, all requirements of this subpart shall be applicable requirements that must be included in an affected EGU’s title V permit. (2) The applicable requirements of this subpart, as well as other terms or conditions necessary to ensure compliance with the applicabl e 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. Th is 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 ch apter. ( 3 ) No title V permit revision shall be required for any crediting, holding, deduction, or transfer of ERCs in accordancewith this subpart, provided that the requirements applicable to such creditings, holdings, deductions, or transfers of ERCs are already incorporated in such permit

. (f) Liability. Any provision of the 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 w ith any other provision of the applicable, approved

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 before the occurrence of an act or event shall 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 P rogram, is not a business day, then the time period shall 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 Tradi ng Program are set forth in part 78 of this chapter. **§ 62.16431**  **What is the Clean Energy Incentive Program?** (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 from the effective date of a federal plan for that state until December 31, 2021: (1) Metered wind power; (2) Metered solar power; and (3) Demand

- side EE that benefits low

- income communities.(b) Early action ERCs will b e distributed pursuant to a process to be prescribed by the Administrator, and in a manner to be demonstrated by the Administrator to have no impact on the aggregate emission performance of affected EGUs required to meet

rate

- based emission standards durin g the compliance periods. (c) The Administrator will match these early action ERCs with additional 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 section and one matching ERC from the match under paragraph (c) of this section ; and (2) For EE projects that benefit low

- income communities as determined by the Administrator solely for purposes of this subpart: for every two MWh in end

- use demand savings achieved, the project will receive two early action ERCs under paragraph (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) of this section

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

− EGU emission rate ) EGU emission standard ∗ EGU generation

Where:
ERCs = N umber of emission rate credits [specify ]

. EGU emission standard = The e missio n 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 emission rate measured in accordance with § 62.16540 (lb/MWh)

. EGU generation = T otal net energy output generation of the affected EGU during the applicable compliance period measured in accordance with 62.16540 (MWh)

. (c) Stationary combustion turbines that meet the definition of an affected EGU may generate net energy output MWh gas shi ft
ERCs (GS

- ERCs) for all hours of operation during a given compliance period according to paragraphs (c)(1) through (3) ofthis section

. (1) To calculate the number of GS

- ERCs:
GS

- ERCs= EGU Generation * Incremental Generation Factor*GS

- ERC Emission Fac Where:
GS

- ERC = [specify ]

. EGU generation = 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 each compliance period

. GS

- ERC Emission Factor Rate = 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:
GS

- ERC Emission Factor = [specify ]

. EGU emission rate = A ffected EGU’s measured CO 2 emission rate measured in accordance with § 62.16540 (lb/MWh)

.Steam turbine emission standard = S team turbine emission standard for the corresponding compliance period as found in Table 1

. (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. Sta tionary combustion turbines may use other ERCs in their compliance demonstration. **§ §62.16435 What eligible resources qualify for generation of**  **ERCs in addition to affected EGUs?** (a) ERCs may only be issued to an eligible resource that meet each of the requirements in paragraphs (a)(1) through (4) of this section. All categories of resources other than on - shore utility scale wind, utility scale solar photovoltaics, concentrated solar power, geothermal power, nuclear energy, or utility scale hydropower , a nd 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 includ e 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 diffe rence in generation between the uprated nameplate capacityand its nameplate capacity prior to the uprate. ERCs must not be issued for generation for an uprate that followed a derate that occurred on after January 1, 2013. A resource that is relicensed

or receives a license extension is considered existing capacity and is not an eligible resources, unless it receives a capacity uprate as a result of the relicensing process that is reflected in its relicensed permit. In such a case, only difference in namepl ate capacity between its relicensed permit and its prior permit is eligible to be issued ERCs. (2) The resource must be connected to, and delivers energy to or saves electricity, on the electric grid in the contiguous United States. (3) The resource is lo cated in a S tate whose affected EGUs are subject to rate

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

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

- based emission standards pursuant to this regulation. (4) The resource falls into one of the following categories of resources: (i) Renew able electric generating technologies using one of the following renewable energy resources: wind, solar,geothermal, hydro, wave, tidal; (ii) Qualifying biomass; (iii) Waste

- to

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

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

- side EE or demand

- side management measure that saves electricity and is calculated on the basis of quantified ex poste savings, not “projected” or “claimed” savings. (b) Any resource that d oes not meet the requirem ents of this subpart cannot generate ERCs for use in the compliance demonstration required under §62.16420. (c) ERCs may not be issued to any of the following: (1) New, modified, or reconstructed EGUs that are subject to subpart TT TT of p art 60 of this chapter , except CHP units that meet the requirements of a CHP unit under paragraph (a) of this section ; (2) EGUs that do not meet the applicability requirements of §62.16410, except CHP units that meet the requirements of a CHP unit u nder paragraph (a) of this section CLEAN AIR ACT ; (3) Measures that reduce CO 2 emissions outside the electric power sector, including GHG offset projects representing emission reductions that occur in the forestry and agriculturesectors, direct air capture, and crediting of CO 2 emission reductions that occur in the transportation s ector as a result of vehicle electrification; and (4) Any measure not approved by the EPA to generate ERCs in connection with a specific S tate plan. **§ §**  **62.16440 What is the process for revocation of qualification**  **status of an eligible resource?** (a) If an eligible resource is found to not meet the requirements of § 62.16435 in the Rate

- based T rading P rogram , then the Administrator will revoke the eligibility of the eligible resource to be issued ERCs. In addition, the provisions of § 62.16450(d) may apply. (b) Any instance of intentional misrepresentation in an eligibility application or monitoring and verification (M&V) report may be cause for revocation of the qualification status of an eligible resource. (c) Repeated instances of error or misstate ment 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 misrepresentati on, or repeated instances of error or misstatement, in program submissions, by the authorized account representative of theeligible resource, the Administrator may prohibit the eligible resource from any further eligibility to be issued ERCs. In addition, the provisions of § 62.16450 (a) through (d) may apply. **§ §62.16445**  **What is the process for the issuance of ERCs**  ? The process and requirements for issuance of ERCs for affected EGUs and 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 requirements in paragraphs (a)(1) through (9) are met . (1) Identification of the authorized account representative of the ERC resou rce, including the authorized account representative’s name, address, e

- mail address, telephone number, and ERC tracking system account number. (2) Identification of the eligible resource(s), including the information in paragraphs (a)(2)(i) through (v) of this section. (i) For an eligible resource, the physical location of the eligible resource; contact information for the owner or operator of the eligible resource, if different from the designatedrepresentative or authorized account representative; eligible

resource generator prime mover and /or technology type; eligible

resource nameplate capacity; eligible resource category (e.g., wholesale generator, wholesale generator also serving onsite customer load, customer

- sited distributed generator) (if

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

. (A) For an 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 electri c generating facility had nameplate capacity of 1 MW or more. (ii) For an energy

- saving resource that is project

- based, a detailed description of the demand

- side EE or electricity savings project, including: location and specifications of the building(s), facility(ies), or installations where energy

- savingmeasures were implemented or will be implemented; owner and operator of the building(s), facility(ies), or installations where the energy

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

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

energy - saving measures installed and/or energy

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

- saving project; project plans and technical schematics, as applicable

. (iii) For an energy

- savings resource that involves an EE require ment or program, a description of the electricity savings program, including: overall approach or “logic” to the requirement or program, including applicable strategies and activities, along with key assumptions regarding how such strategies and activities will achieve quantifiable reductions in electricity consumption; location and geographic distribution of the targeted building(s), facility(ies), or installations where energy

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

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

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

- savingrequirement or program, including lead contractor(s), subcontractor(s), and consulting firms (if different from the authorized account representative); specifications of energy

saving equipment and/or energy

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

- site audits paired with technical recommendations

. (iv) Fo r other electricity

- saving resources (e.g., DSM measures, T &D efficiency improvements and other T&D measures such as CVR), a description of the resource, including: overall approach or “logic” to the electricity

- saving resource, including applicable strate gies and activities, along with key assumptions regarding how such strategies and activities will achieve quantifiable reductions in electricity consumption; location and geographic distribution of the targeted building(s), facility(ies), or electricity tr ansmitting and distributing systems, as applicable, where electricity

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

- use(s) where the electricit y - saving resource are implemented or will be implemented; the parties implementing the electricity

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

saving resource, as applicable

. (v) For eligible resources with distributed locations, such

as measures at multiple residential, commercial, or industrial buildings, at a minimum, aggregated information about the location of measures that constitute an eligible resource, provided that the accredited independent verifier and the Administrator have th e 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 S tates are providing for joint issuance of ERCs pursuant to the authority in their individual 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.( 7 ) An authorization that provides for the following: the Admi nistrator may inspect (including a physical inspection of the eligible resource and its meter) and/or audit the eligible resource at any time and verify that the eligible resource and the EM&V plan have been implemented as described in the eligibility appl ication. ( 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 a nd 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, a nd complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment. ” (ii) [Reserved] ( 9 ) Any other information requ ired 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 aremet, approve the eligibility application and register the affected EGU or eligible resource in an ERC tracking system that meets the requirements of § 62.16515. Once so registered, the affected EGU or eligible resource is eligible to be iss ued ERCs, provided all other applicable requirements continue to be met. (c) M&V reports . For an eligible resource, the designated representative must submit to the Administrator an M&V report prior to issuance of ERCs by the Administrator. (d) Verific ation reports . For an eligible resource, the authorized account representative must submit a verification report from an accredited independent verifier that meets the requirements of § 62.16470 and §62.16475 as part of each eligibility application and M&V report. While considered a part of the eligibility application and M&V report, the verification report must be submitted separately by the accredited independent verifier to the Administrator. (e) Issuance of ERCs . ERCs may only be issued by the Administrator based on actual electricity generation or savings documented in an M&V report that meets the requirements of
§ 62.16460 and a verification report that meets the requirements of § 62.16465. Only one ERC will be i ssued for each verified MWh. (f) Tracking system . ERCs may only be issued through an ERC tracking system that meets the requirements of § 62.16515. **§ §**  **62.16450 What is the process for error adjustments or** **misstatement, and suspension of ERC issuance?** (a) In the event of error or misstatement of quantified MWh of electricity generation or savings in a previous M&V report for which ERCs have been issued, the Administrator may adjust the number of ERCs issued in a subsequent reporting period to address 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 the event that the general account of the eligible resource holds an insufficient number of ERCs to correct the error or misstatement, the authorized account representative shall submit to the Administrator within 30 days a number of ERCs necessary to correct the error or misstatement. Failure to meet this requirement will result in prohibition of the authorized account representative for the eligible resource from furtherparticipation in the program, unless reauthorized at the discretion of the Administrator. (c) The Administrator may freeze the general account held by 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 n authorized account representative of an eligible resource pending investigation of potential misrepresentation, error, or misstatement in an eligibility application of an eligible

resour ce, or in an M&V report for which ERCs have been issued. Freezing a general account will prevent transfer of ERCs out of the account. (d) If ERCs are issued for an eligible resource that is found to be ineligible, then the Administrator may take the actions in paragraphs ( d) ( 1 ) through ( 3 ) of this section

. ( 1 ) Freeze the general account for the e ligible resource, preventing any transfers of ERCs out of the account. ( 2 ) Revoke and deduct ERCs held in the general account of the authorized account repres entative eligible resource, in a number equal to the number of ERCs issued for the ineligible eligible resource. ( 3 ) In the event that the general account of the ERCresource 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 submit to the Administrator within 30 days a number of ERCs necessary to fully account for all ERCs issued for the ineligible eligible resource. Failure to meet this requirement will result in prohibition of the eligible resource from further participation in the program, unless reauthorized at the discretion of the Administrator. (e) The Administrator may temporarily or permanently suspend issuance of ERCs for an eligible resourc e, for the following reasons in paragraphs ( e) ( 1 ) through ( 3 ) of this section. ( 1 ) Pending investigation of potential misrepresentation, error, or misstatement in an M&V report, for which ERCs have been issued, or the eligibility status of an eligible reso urce. ( 2 ) In the case of repeated error or misstatements in submitted M&V reports. ( 3 ) In the case of an intentional misrepresentation in a submitted M&V report. **Evaluation Measurement and Verification Plans, Monitoring and Verification Reports, and Verif**  **ication §**  **§ 62.16455 What are the requirements for evaluation measurement**  **and verification plans for eligible resources?**(a) EM&V plan requirements. Any EM& V plan submitted in support of the issuance of an ERC pursuant to this rule must meet the requirements of this section. (b) General EM&V plan criteria. Each EM&V plan must identify the eligible resource and its approved eligibility application. (c) Specif ic 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 crite ria 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 (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 a meter used by a control area operator for financial settlements, or a meter that meets the American National Standards Institute No. C12. 20. , Code for Electricity Metering,metering accuracy standards, or a meter that meets an alternative equivalent standard that has been approved in advance of its use to measure generation pursuant to this regulation by the EPA. (ii) The generating data is measured at the generator’s bus bar, or, for a renewable energy resource with a nameplate capacity of less than 10 kW that is interconnected behind an individual business or household meter, the generating data was measured at the AC output of the inverte r and adjusted to reflect the only energy delivered into either the transmission or distribution grid at the generator bus bar and not and any energy used on

- site at the generator. (iii) The generation data from only one eligible resource generating unit may be associated with each meter, and generation data may not be aggregated, unless all the following provisions are met: (A) All of the generating units have the same essential generation characteristics ; (B) All of the generating units are located in t he same
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 connect ionwith the specific 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 generatio n 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 c ontrol area operator, in which case the generation data must be collected by manual meter readings conducted by an independent verifier that is either not affiliated with the owner or operator of the qualifying renewable energy generating resource or is pr ecluded pursuant to the relevant S tate plan from the ability to transfer or retire ERCs issued to that qualifying renewable energy generating resource or, if the generating unit is less than 10 kw and does not generate enough electricity to enable monthly reporting, the data may be self

- reported and reported no less than annually. (v) The generation data serves a load that otherwise would have been served by the grid if not for the generator. Specifically: (A) ERCs shall not be issued for energy generation used to supply the ancillary equipment used to operate a generatingstation or substation (“station service”) or parasitic load on the generator’s side of the point of interconnection ; and (B) For generators interconnected to transmission syste ms and with on

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

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

- site load and station service. (vi) Any other requirements approved by the EPA in connection with the specific 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 1 0 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 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 di stribution 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 th e generating units are located in the sameS 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 require ments approved by the EPA in connection with the specific 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 irradiance, depending on the resource), or engineering i nformation 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 r eporting, 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 ERCis only based on generation transferred from the eligible resource to the transmission or distribution grid, and is not based on the generation used on

- site by the c ustomer. (vi) Any other requirements approved by the EPA in connection with the specific S tate plan pursuant to which that EM&V plan is submitted. (3) For qualif ied biomass feedstocks used, in addition to the requirements of paragraphs (c)(1) or (2) of th is section, whichever section is applicable, each EM&V plan must demonstrate that the requirements approved by the Administrator for that biomass feedstock and its associated biogenic CO 2 in connection with that S tate plan have been met. (4) For a waste

- t o - energy resource, in addition to the requirements of paragraphs (c)(1) or (2) of this section, as applicable, and paragraph (c)(3) of this section, each EM&V plan must specify: (i) 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 wit h the specific S tate plan pursuant to which that EM&V plan is submitted demonstratethat 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 para graphs (c)(1) or (2) of this section, as applicable, and paragraph (c)(3) of this section, each EM&V plan must meet one of the requirements in paragraphs (c)(5)(i) through (iii ) of this section , as applicable, and any other requirements approved by the EPA in connection with the specific
S tate 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 requireme nts that apply to an affected EGU under
§ 62.16540 of this subpart. (ii) If the combined heat and power unit has an electric generating capacity less than or equal to 25 MW and it uses only natural gas and/or distillate fuel oil, then the EM&V plan must

mee t the low mass emission unit CO 2 emission monitoring and reporting methodology in 40 CFR 75. (iii) If the combined heat and power unit has an electric generating capacity less than or equal to 25 MW and it uses anything other than only natural gas and/or d istillate fuel oil, then the EM&V plan must [....]. ( 6) For demand

- side electricity savings that avoid a transmission and distribution loss, each EM&V plan must measurethe 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 Electri city 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 project must specify how each of the requirements in paragraphs (c)(7)(i) through (x) of this sect ion will be met in quantifying the electricity savings from that EE program or project

. (i) All electricity savings must be quantified on an ex

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

- time basis, which means at the time the electricity savings are occurring. Electricity savings must not be quantified on an ex

- ante basis, which means estimates of MWh savings that are generated prior to implementing the subject EE activity, and that are not quantified using EM&V metho ds 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 orguideline was selected and will be applied to the specific EE

APMP covered in the E&V plan, and an explanation of why that particular protocol or guideline was selected. Protocols and guidelines are considered to be best practice if they: (A) Have gone through a rigorous and credible peer review process that shows the applicable methods to be valid through empirical testing ; and (B) Have been accepted and approved for use by identifiable state regulatory commissions

. Examples of such protocols and guid elines that may be provided in EM&V guidance issued by the Administrator will be treated as presumptively acceptable

. ( iii) All electricity savings must be quantified as the difference between the observed electricity use and a common practice baseline (CP B), which is the equipment that would typically have been installed

– or that a typical consumer or building owner would have continued using

– in a given circumstance (i.e., a given building type, EE program type or delivery mechanism, and geographic regi on) at the time of EE implementation. Examples of CPBs for specific EE programs and projects, and for certain EM&V methods, that may be provided in EM&V guidance issued by the Administrator will be treated as presumptively acceptable. The EM& V plan must specify the reason the specific CPB was selected for that EE program or project , which must include an analysis of the appropriateness of thatCPB for the EE measure covered in the EM&V plan , based on : (A) Characteristics of the EE program or p roject ; (B) The delivery mechanism used to implement the EE program or project (e.g., installed as part of a utility program direct install program versus a point

- of

- sale rebate) ; (C) Local consumer and market characteristics ; (D) Applicable building energy codes and standards and average compliance rates ; and (E) The method applied: project

- based measurement and verification (PB

- MV), comparison group approaches, or deemed savings. (iv) All electricity savings must be quantified by applying one or mor e 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 betwee n a comparison group’s electricity use and the electricity use of EE program participants. Comparison group approaches may include randomized control trials and quasi

- experimental methods, as described in industry best

- practice protocols and guidelines. I f such approaches are documented in EM&V guidance issued by the Administrator, they will be treated as presumptively acceptable.(B) If deemed savings are used, then the EM& V plan must specify that the deemed savings values will only be used for the specific EE measure for which they were derived. The EM&V plan must also specify the name and Web address of the technical reference manual (TRM) in which all deemed electricity s avings values will be documented. Prior to use in an EM&V plan, all TRMs must undergo a review process in which the public, stakeholders, and experts are invited

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

– to provide co mment, have at least 2 months to provide comment, and in which all such comments and associated responses are made publicly available. All TRMs must also be publicly accessible over the full period of time in which they are being used in conjunction with a n EM&V plan for the purpose of quantifying 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 u nder which the value can be applied (including the climate zone, building type, manner of implementation, applicable end uses, operating conditions, and effective useful life), and the manner in which the electricity savings value was quantified, which mus t include applicable engineering algorithms, source documentation, specific assumptions, and other relevant data to support thequantification of savings from the subject EE technology or

measure . (v) All EE programs and projects 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 or project, expected variability in electricity savings (where greater variability necessitates more frequent quantification), the expected scale and magnitude of the electricity savings (where greater quantities of savings necessitate more frequent quantification), and the experience implementing and quantifying savings from the resource (where less exp erience

– for example, with new and innovative 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 project, 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 project, as relevant for the type of program or project and factors listed in paragraph (c) (7)( v) of

t his section ; and(C) Annually for commercial and industrial projects, unless the resource provider can provide a reasonable justification in the EM&V plan for why an annual time interval is not feasible, and can additionally explain how the accuracy and re liability of savings values will not be lessened. ( vi) EM&V plans must specify and document how the EM&V components in paragraphs (c)(7)(vi)(A) through (E) of this section will be analyzed, considered, or otherwise addressed in the quantification and verif ication of electricity savings

. (A) The effects of changes in independent factors on reported electricity savings ( i.e., factors that are not directly related to the EE measure, such as weather, occupancy, and production levels. (B) The effective useful life (EUL) or duration of time the EE measure is anticipated to remain in place and operable with the potential to save electricity, which must be based on the application of EM&V methods, an industry best

- practice persistence study, deemed estimates of ef fective useful life, or a combination of all three. 1 ) If deemed estimates of effective useful life are used, then they must specify the date by which the EE measure will stop saving electricity. ( 2 ) If industry best

- practices persistence studies are used to modify an effective

- useful

- life value, then they must beconducted at least every 5 years. (C) The potential sources of double counting, and the associated steps for avoiding and correcting for i t, such as: ( 1 ) For programs and projects with identified participants, track the type and number of EE measures implemented at the utility

- customer level. ( 2 ) For programs without identified participants, such as point

- of

- sale rebates and retailer or manufacturer incentive programs, track applicable vendor, retailer, and manufacturer data. ( 3 ) For programs and individual EE projects (such as those implemented by an energy service company) that both have identified participants, use tracking data to avoid and correct for double counting that may occur across the two ; and ( 4 ) For programs with identified participants and those without (such as retail incentives to purchase energy

- efficient equipment), use program tracking data for the former and use applicable vendor, retailer, and manufacturer data for the latter to avoid and correct for double counting that may occur across the two. ( D) The savings verification approaches for ensuring that EE equipment has been properly installed, is operating as intended, and therefore has the potential to save electricity, including how verification will be carried out within the firstyear of implementation of the EE program or project using best

practice approaches, such as physical inspections at a customer

pr emises, phone and mail surveys, and reviews of sales receipts and other documentation . If such approaches are documented in EM&V guidance issued by the Administrator, they will be treated as presumptively acceptable. (E) The i nteractive effects of EE mea sures 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, project, or measure (e.g., lighting retrofits to improve EE can reduce waste heat to the surrounding conditioned space, and therefore may increase the required electric heating load in a facility or premises). (vii) The EM&V plan must specify how the accuracy and reliability of the electri city savings of the EE program or project will be assessed, and must discuss the rigor of the method selected to quantify the electricity savings. It must also discuss the approaches that will be used to control all relevant types of bias and to minimize t he potential for systematic and random error, as well as the program

- or project

specific circumstances in which such bias and error are likely to arise. Approaches to minimizing bias and error are discussed in the EM&V guidance issued by the Administrator

.(viii) If sampling will be used to quantify the electricity savings from an EE program, then the MWh estimates derived from sampling must have at least 90 percent confidence intervals whose end points are no more than +/

- 10 percent of the estimate, and the statistical precision of the associated estimates must be specified in the EM&V plan. (ix) All data sources and key assumptions used to quantify electricity savings must be described in the EM&V plan. (x) Any additional information necessary to demo nstrate that the electricity savings were appropriately quantified and verified. Considerations for quantifying and verifying savings from several EE activities are described in the EM&V guidance provided by the Administrator. (d) You must ensure that an y 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 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 thepossibility of fine or imprisonment. ” **(2) [Reserved] §**  **62.16460 What are the requirements for monitoring and verification reports**  **for eligible resources?** (a) M&V report requirements. Any M&V report that is submitted, in support of the issuance of an ERC that can be used in accordance with §62.16420, must meet the requirements of this section. (b) General M&V report criteria. Each M&V report must include the following: ( 1 ) For the first M&V report submitted, documentation that the electricity

- generating resources, electricity

- saving measures, or practices were installed or implemented consistent with the description in the approved eli gibility application required in § 62.164 4 5(a) ; and ( 2 ) For 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 period to generate the quantified MWh of generation or MWh of electricity savings ; ( iii ) D ocumentation (i ncluding data) of the energy generation and/or electricity savings from any activity,project, measure, resource, or program addressed in the EM&V report, quantified and verified in MWh for the period covered by the M&V report, in accordance with its EM&V plan, and based on

ex - post energy generation or savings ; ( iv ) 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 ei ther certification that the e ligible resource continued to meet all eligibility requirements during the reporting period covered by the M&V report or disclosure of any material changes to the eligible resource from the description of the eligible resource in the approved eligibility application, which must include any change in the energy generation (e.g., nameplate MW capacity) or electricity savings capability of the qualifying eligible resource (including the date of the change) ; and ( v ) 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 report submitted pursuant to this subpart includes the following certification: (1) “ I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on myinquiry 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, includ ing the possibility of fine or imprisonment. ” **(2) [Reserved] §62.16465**  **What are the requirements for verification reports?** (a) A verification report included as part of an eligibility application or an M&V report must meet the requirements of paragraph (b ) of this section (for the eligibility application verification report) and paragraph (c) of this section (for the M&V report verification report) and include the following: (1) A verification statement that sets forth the findings of the accredited indep endent 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 contai ns any material misstatements or material data discrepancies, and whether the submittal conforms with applicable regulatory requirements. The verification statement must clearly identify how levels ofassurance and materiality are defined as part of the ve rifier

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

att achments. Based on my personal knowledge and/or inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment. ” (b) A verification report included as part of an eligibilit y application must, at a minimum, describe the review conducted by the accredited independent verifier and verify each of the following: (1) The eligibility of the eligible resource to be issued ERCs pursuant to this regulation, in accordance with §62.16 435 and **§** 62.16445(a), including an analysis of the adequacy and validity of the information submitted by the authorized account representative to demonstrate that the eligible resource meets each applicable requirement of §62.16435 and **§** 62.16445(a).(2) T he eligible resource is not duplicative of a resource used to meet emission standards or a state measure in another approved 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 energ y 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 info rmation 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 adeq uacy and validity of the information and data submitted in the submittal by the authorized account representative to quantify eligible MWh of electric generation or electricity savings during the period for which the authorized account representative seeks issuance of ERCs, aswell 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 te chnically feasible range for that specific e ligible resource. (i) For metered generation, the data validity check must compare reported electricity generation to an engineering estimate of the maximum generation potential of the qualified renewable energy resource, based on, at a minimum, its maximum nameplate capacity in MW and the number of days since the prior cumulative meter reading was entered in the ERC tracking system. If the data entered exceeds the estimated technically feasible generation, then t he reported data and the estimate must be analyzed in the verification report. (ii) For all electricity generated or saved, the accredited independent verifier must describe the likely source of any data discrepancy and determine in the verification report any MWh generated or saved. (2) The M&V report meets the requirements of § 62.16460

. (3) Any other information required by the Administrator or that the accredited independent verifier finds, in its professional opinion, is necessary to assess the adequa cy and validity of information and data supplied by the authorized account representative.**§ §62.16470**  **What is the accreditation procedure for independent verifiers?**  (a) Only Administrator

- accredited independent verifiers may provide a verification report for an eligibility application or M&V report. (b) Applications for accreditation must follow a procedure and form specified by the Administrator which shall include a demonstration by the verifier that it meets the requirements in paragraph ( c ) of this se ction

. ( c ) Independent verifiers must meet each of the requirements in paragraphs ( c )(1) through (6) of this section to be accredited. (1) Independent verifiers must have the skills, experience, resources (personnel and otherwise) to provide verification reports, including the following: ( i ) Appropriate technical qualification (professional engineer or otherwise) to evaluate the eligible resource for which the independent verifier is seeking accreditation, which may include ANSI accreditation under ISO 1 4065 for GHG validation and verification bodies ; ( ii ) Appropriate auditing and accounting qualifications for financial and non

- financial data monitoring, auditing, and quality assurance and quality control to evaluate the eligibleresource for which the i ndependent verifier is seeking accreditation ; ( iii ) Knowledge of the requirements of the Administrator’s
CO 2 Rate

- based Trading Program regulations and related guidance ; ( iv ) Knowledge of the eligible resource categories for which the independent verifi er is seeking accreditation, including relevant aspects of the design, operation, and related energy generation or electricity savings monitoring and reporting approaches for such eligible resources ; and ( v ) Capability to perform key verification activiti es, such as development of a verification report; performance of site visits; review and recalculation of reported data; review of data management systems; review of quantification methods used in accordance with an approved EM&V plan; preparation of a

ver ification statement, list of findings, and verification report; and internal review of the verification findings and report. (2) Independent verifiers must document, in the application for accreditation, the independent verifiers that will provide verific ation services, including lead verifiers, key personnel and any contractors or subcontractors (collectively, accredited independent verification team) and demonstrate that they meet the requirements of section § 62.16470(d)(1). Once accredited, only the acc redited independent verification team identified inthe accreditation application and accredited by the 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 resource category for which it is accredited. (4) Prospective independent verifiers must meet the requirements of **§** 62.16475(d) through (f) and demonstrate that they have in place adequate systems and protocols to identify, disclose and avoid potential conflicts of interest. (5) An accredited independent verifier must not be debarred, suspended, or proposed for debarment pursuant to the
Govern ment

- wide Debarment and Suspension regulations, 40 CFR part 32, or the Debarment, Suspension and Ineligibility provisions of the Federal Acquisition Regulations, 48 CFR part 9, subpart 9.4. (6) An accredited independent verifier must maintain, for its employees, and ensure the maintenance of, for any parties that it employs, professional liability insurance, as defined in 31 C.F.R. 50.5(q), through an insurance provider that possess a financial strength rating in the top four categories from either
Stan dard & Poor’s or Moody’s, specifically, AAA, AA, A or BBB for Standard & Poor’s, and Aaa, Aa, A, or Baa for Moody’s. Anyentity covered by this paragraph shall disclose the level of professional liability insurance they possess when entering into

contracts to provide verification services pursuant to this regulation. ( d ) Requirements for maintenance of accreditation status , as follows : (1) Accredited independent verifiers must meet the requirements of section 62.16475 when providing verification services f or a n authorized account representative ; and (2) The instances specified in section 62.16475(d) are cause for revocation of a verifier’s accreditation. **§ §62.16475**  **What are the procedures of accredited independent verifiers must follow to avoid conflict of**  **interest?** (a) Accredited independent verifiers must not provide verification services for any eligible resource for which it has a conflict of interest ( COI ) , which means: (1) Accredited independent verifiers must have, or have had, no direct or indirect financial interest in, or other financial relationships with, an e ligible resource, or any prospective eligible resource, for which the y seek to provide a verification repor t ; (2) Accredited independent verifiers must have, or have had, no direct or indirect organizational or personal relationships with an eligible resource, that would impact theirimpartiality in assessing the validity and accuracy of the information in an e ligibility 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 n authorized account representative seeks issuance of ERCs, beyond the prov ision of verification services ; (4) Accredited independent verifiers must not be compensated, financially or otherwise, directly or indirectly, on the basis of the content of its verification report (including eligibility approval of an eligible resource, the quantified and verified MWh in an M&V report, ERC issuance, or the number of ERCs issued) ; (5) Accredited independent verifiers must not own, buy, sell, or hold ERCs, or other financial derivatives related to ERCs, or have a financial relationship w ith 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 reportbefore its submittal to the Administrator, and the accredited independent verifier must share any d rafts 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 e ligible resource for the provision of verification services shall not constitute a COI
. (c) Verification reports must include an attestation by the accredited independent verifier that it evaluated and disclosed to the Administrator any potential COI related to an e ligible

resource. (d) Prior to engaging for the provision of verification

serv ices, an accredited independent verifier must demonstrate that it has no COI related to the e ligible resource, as specified in paragraph (a) of this section . If a COI is identified for a person or persons within an accredited independent verifier for a spe cific subject or verification, in accordance with paragraphs (e) and (f) of this section , then an accredited independent verifier may propose to the Administrator steps that will be taken to eliminate the COI which shall include prohibiting the person or p ersons 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 theverification services. In no instance shall an accredited independent verifier engage in verification services for an

e ligible resource without the approval of the Administrator. (e) Prior to engaging in verification services and writing a verification report, an accredited independent verifier shall disclose to the Administrator all information necessary for the Administrator to evaluate a potential COI (including information concerning its ownership, past and current clients, rel ated entities, as well as any other facts or circumstances that have the potential to create a COI ). (f) Accredited verifiers shall have an ongoing obligation to disclose to the Administrator any facts or circumstances that may give rise to a COI as defin ed in paragraph (a) of this section

. (g) The Administrator may reject a verification report from an accredited independent verifier, if the Administrator determines that the accredited independent verifier has a COI as defined in paragraph (a) of this sec tion . If the Administrator rejects an accredited independent verifier report for such

reasons, then the eligibility application or M&V report submittal must be deemed incomplete and ERCs must not be issued pursuant to it. **§ §**  **62.16480 What is the process for**  **the revocation of accreditation status for an independent verifier?** (a) The Administrator may revoke the accreditation of an independent verifier at any time for cause, including for the reasons specified in paragraphs (a)(1) through (4) of this section

. (1) Failure to fully disclose any issues that may lead to a
COI with respect to an 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 verifica tion services. (3) Negligence in the conduct of verification activities, or neglect of responsibilities pursuant to the requirements of
§ § 62.16465, 62.16470, and 62.16475. (4) Intentional misrepresentation of data in a verification report. (b) [Reserved] **Designated Representatives §62.16485**  **How are designated representatives and alternate designated representatives authorized? What role do authorized**  **designated representatives and alternate designated representatives play?**  (a) Except as provided under §62.16495, each affected EGU, and each eligible resource shall have one and only one designated 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 act in accordance with the certification statement in § 62.16500(a)(4)(iii). (2) Upon and after receipt by the Administrator of a complete certificate of representation under § 62.16500: (i) The desi gnated 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 decision or order issued to the designated representative by the Administrator re garding 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 repre sentative is selected shall 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 ofthe affected EGU and shall act in accordance with the certification statement in § 62.16500(a)(4)(iii). (2) Upon and after receipt by the Administrator of a complete certificate of representation under §62.16500, (i) The alternate designated representative shall be authorized; (ii) Any representation, action, inaction, or submission by the alternate designated representative shall be deemed to be a representation, action, inaction, or submission by the designated representative; and (iii) The owners and operators of the affected EGU shall be bound by any decision or order issued to the alternate designated representative by the Administrator regarding any such affected EGU. (c) Except in this section, §§62.16490 through 62.16510, and §62.16570, whenever the term “designated representative” (as distinguished from the term “common designated representative”) is used in this subpart, the term shall be construed to include the designated representative or any alternate designated representative. **§62 .16490**  **What responsibilities do designated representatives and alternate designated representatives hold?**  (a) Except as provided under §62.16510 concerning delegation of authority to make submissions, each submissionunder the CO 2 Rate

- based Trading Program shall 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 include the following certification statement by the designated representative or alternate designated representative: “I am authorized to make this submission on behalf of the owners and operators of the affected EGU for which the submission is made. I certify under penalty of law that I ha ve 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 statemen ts 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 possi bility of fine or imprisonment.” (b) The Administrator will accept or act on a submission made for an affected EGU only if the submission has been made, signed, and certified in accordance with paragraph (a) of this section and §62.16510.**§ §**  **62.16495 What a**  **re 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 supe rseding complete certificate of representation under §62.16500. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous designated representative before the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new designated representative and the owners and operators of the affected EGU. (b) Changing alternate designated representative. The alternate designated representative may be changed at a ny time upon receipt by the Administrator of a superseding complete certificate of representation under §62.16500. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate designated representative before the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new alternate designated representative, the designated representative, and the owners and operators of the affected
EGU
.(c) Ch anges in owners and operators. (1) In the event an owner or operator of an affected EGU is not included in the list of owners and operators in the certificate of representation under §62.16500, such owner or operator shall be deemed to be subject to and bound by the certificate of representation, the representations, actions, inactions, and submissions of the designated representative and any alternate designated representative of the affected EGU, and the decisions and orders of the Administrator, as if the owner or operator were included in such list. (2) Within 30 days after any change in the owners and operators of affected EGU, including the addition or removal of an owner or operator, the designated representative or any alternate designated represen tative shall submit a revision to the certificate of representation under §62.16500 amending the list of owners and operators to reflect the change. (d) Changes in affected EGUs at the source. Within 30 days of any change in which affected EGUs are located at a source (including the addition or removal of an affected EGU), the designated representative or any alternate designated representative shall submit a certificate of representation under §62.16500 amending the list of affected EGUs to reflect the cha nge.(1) If the change is the addition of an affected EGU that operated (other than for purposes of testing by the manufacturer before initial installation) before being located at the source, then the certificate of representation shall identify, in a for mat 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 obtaine d, 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 identify, in a format prescribed by the Administrator, the entity to which the affecte d 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 longe r located at the source. **§62.16500 What must be included in a certificate of**  **representation?** (a) A complete certificate of representation for a designated representative or an alternate designated representative shall include the elements in paragraphs (a) (1)through (5) of this section in a format prescribed by the Administrator

. (1) Identification of the affected EGU for which the certificate of representation is submitted, including names, source category and NAICS code (or, in the absence of a NAICS code, an equivalent code), State, plant code, county, latitude and longitude, unit identification number and type, identification number and nameplate capacity (in MWe, rounded to the nearest tenth) of each generator served by each such affected EGU, net

- s ummer 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 co mmencement of commercial operation shall 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 de signated representative. (3) A list of the owners and operators of the affected EGU

. (4) The following certification statements by the designated representative and any alternate designated representative :(i) “I certify that I was selected as the designat ed 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 th e 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 li fe

- 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 ea ch owner and operator of the affected EGU ; and ERCs and proceeds of 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 reserv ation 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 i n accordance with the contract.” (5) The signature of the designated representative and any alternate designated representative and the dates signed. (b) Unless otherwise required by the Administrator, documents of agreement referred to in the certificate of representation shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted. **§62.16505 What is the Administrator’s role in objections**  **concerning designated representatives and alternate designated representatives?**  (a) Once a complete certificate of representation under §62.16500 has been submitted and received, the Administrator

w ill 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 communicati on 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 o f the designated representative or alternate designated representative or the finality of any decision or order by the Administrator under the CO 2 Rate

- based Trading Program. (c) The Administrator will not adjudicate any private legal dispute concerning th e authorization or any representation, action, inaction, or submission of any designated representative or alternate designated representative, including private legal disputes concerning the proceeds of ERC transfers. **§62.16510 What process must designate**  **d representatives and alternate designated representatives follow to delegate their**  **authority?** (a) A designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart. (b) An alternate designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart. (c) In ord er 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 representat ive 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 lis t 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 representat ive: (i) “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 62.16510(d) shall be deemed to be an electronic submission by me ” ; and(ii) “Until this notice of delega tion 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 superseding notice of delegation submitted by such designated representative or alternate designated representative, as appropriate. The superseding notice of delegation may replace any previously i dentified 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 paragr aph (d) of this section shall be deemed to be an electronic submission by the designated representative or alternate designated representative submitting such notice of delegation. **Monitoring, Recordkeeping, Reporting §**  **62.16515 How are compliance accounts**  **and general accounts established and used**  **, and how is ERC issuance documentation**  **accessed?** (a ) Compliance accounts. (1) Upon receipt of a complete certificate of representation under §62.16500, the Administrator will establish a compliance account for the affected EGU for which the certificate of representation was submitted, unless the affected EGU already has a compliance account. The designated representative and any alternate designated representative of an affected EGU shall be the authorized

accou nt representative and the alternate authorized account representative respectively of the compliance account. (2) A compliance account will hold ERCs intended for surrender by a designated representative when demonstrating an affected EGUs compliance with a 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 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 hel d by the Administrator, and ERCs deposited into it are permanently retired. Once an ERC isretired, the ERC shall no longer be transferable to another account in that ERC tracking system or any other ERC tracking system. (2) [Reserved] (c) General accounts

. (1) Application for a general account

. (i) Designated representatives of affected EGUs, authorized account representatives of eligible resources, and any other person may apply to open a general account, for the purpose of holding and transferring ERCs, by submitting to the Administrator a complete application for a general account. Such application shall designate one and only one authorized account representative and may designate one and only one alternate authorized account representative who may act on behalf of the authorized account representative. (A) The authorized account representative and alternate authorized account representative shall be selected by an agreement binding on the persons who have an ownership interest with respect to ERCs held in the general account. (B) The agreement by which the alternate authorized account representative is selected shall include a procedure for authorizing the alternate authorized account representative to act in lieu of the authorized account representativ e.(ii) A complete application for a general account shall include the following elements in a format prescribed by the Administrator: (A) Name, mailing address, e

- mail address (if any), telephone number, and facsimile transmission number (if any) of the a uthorized account representative and any alternate authorized account representative; (B) An identifying name for the general account; (C) A list of all persons subject to a binding agreement for the authorized account representative and any alternate auth orized account representative to represent their ownership interest with respect to the ERCs held in the general account; (D) The following certification statement by the authorized account representative and any alternate authorized account representative : “I certify that I was selected as the authorized account representative or the alternate authorized account representative, as applicable, by an agreement that is binding on all persons who have an ownership interest with respect to ERCs held in the gene ral account. 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 such persons and that each such person shall be fully bound by my representations, actions, ina ctions, or submissions and by anydecision or order issued to me by the Administrator regarding the general account ” ; and (E) The signature of the authorized account representative and any alternate authorized account representative and the dates signed. ( iii) Unless otherwise required by the Administrator, documents of agreement referred to in the application for a general account shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the suff iciency of such documents, if submitted. (2) Authorization of authorized account representative and alternate authorized account representative . (i) Upon receipt by the Administrator of a complete application for a general account under paragraph ( c )(1) of this section, the Administrator will establish a general account for the person or persons for whom the application is submitted, and upon and after such receipt by the Administrator: (A) The authorized account representative of the general account shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each person who has an ownership interest with respect to ERCs held in the general account in all matters pertaining to the CO 2 Rate

- bas ed 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 altern ate authorized account representative shall be deemed to be a representation, action, inaction, or submission by the authorized account representative ; and (C) Each person who has an ownership interest with respect to ERCs held in the general account shall be bound by any decision or order issued to the authorized account representative or alternate authorized account representative by the Administrator regarding the general account. (ii) Except as provided in paragraph ( c )(5) of this section concerning de legation of authority to make submissions, each submission concerning the general account shall be made, signed, and certified by the authorized account representative or any alternate authorized account representative for the persons having an ownership i nterest with respect to ERCs held in the general account. Each such submission shall include the following certification statement by the authorized account representative or any alternate authorized account representative: “I am authorized to make this su bmission on behalf of the persons having an ownership interest with respect to the ERCs held in the general account. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this docu ment andall 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 aw are that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.” (iii) Except in this section, whenever the term “authorized

accoun t 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 repr esentative; changes in persons with ownership interest

. (i) The authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph ( c )(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous authorized account representative before the time and date when the Administrator receives the superseding application for a g eneral account shall be binding on the new authorized account representative and the persons with an ownership interest with respect to the ERCs in the general account.(ii) The alternate authorized account representative of a general account may be change d 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 al ternate authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new alternate authorized account representative, the authorized account representat ive, and the persons with an ownership interest with respect to the ERCs in the general account. (iii)(A) In the event a person having an ownership interest with respect to ERCs in the general account is not included in the list of such persons in the appl ication 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 ac count representative of the account, and the decisions and orders of the Administrator, as if the person were included in such list. (B) Within 30 days after any change in the persons having an ownership interest with respect to ERCs in the general

account , including the addition or removal of a person, theauthorized account representative or any alternate authorized account representative shall submit a revision to the application for a general account amending the list of persons having an ownership inte rest with respect to the ERCs in the general account to include the change. (4) Objections concerning authorized account representative and alternate authorized account representative

. (i) Once a complete application for a general account under paragraph ( c)(1) of this section has been submitted and received, the Administrator will rely on the application unless and until a superseding complete application for a general account under paragraph ( c )(1) of this section is received by the Administrator. (ii) Ex cept as provided in paragraph ( c )(4)(i) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account shall affect any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative or the finality of any decision o r 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 account representative of a general account, including private legal disputes concerning the proceeds of ERCs transfers. (5) Delegation by authorized account representative and alternate authorized account represe ntative

. (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 a uthorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart. (iii) In order to delegate authority to a natural person to make an electronic submission to the Administrator in accordance with paragraph ( c )(5)(i) or (ii) of this section, the authorized account representative or alternate authorized account representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:(A) The name, address, e

- mail address, telephone number, and facsimile transmission number (if any) of such authorized account repr esentative 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 natura l person, a list of the type or types of electronic submissions under paragraph ( c )(5)(i) or (ii) of this section for which authority is delegated to him or her; (D) The following certification statement by such authorized account representative or alterna te authorized account representative: “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am an authorized account representative or alternate authorized representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 62.16515( c )(5)(iv) shall be deemed to be an electronic submission b y me ”; and (E) The following certification statement by such authorized account representative or alternate authorizedaccount representative: “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 62.16515( c )(5)(iv), I agree to maintain an e

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

- mail address unless all delegation of authority by me under 40 CFR 62.16515(c)(5) is terminated .” (iv) A notice of delegation submitted under paragraph ( c )(5)(iii) of this section shall be effective, with regard to the authorized account representative or alternate authorized account representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administ rator 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 agen t, or eliminate entirely any delegation of authority. (v) Any electronic submission covered by the certification in paragraph ( c )(5)(iii)(D) of this section and made in accordance with a notice of delegation effective under paragraph (c)(5)(iv) of this sec tion 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 authoriz ed account representative ofa general account may submit to the Administrator a request to close the account. Such request shall include a correctly submitted ERC transfer under §62.16525 for any ERCs in the account to one or more other Allowance Tracking and Compliance System accounts. (ii) If a general account has no ERC transfers to or from the account for a 12

- month period or longer and does not contain any ERCs, then the Administrator may notify the authorized account representative for the account that the account will be closed after 30 days after the notice is sent. The account will be closed after the 30

- day period unless, before the end of the 30

- day period, the Administrator receives a correctly submitted ERC transfer under §62.16525 to the acc ount or a statement submitted by the authorized account representative or alternate authorized account representative demonstrating to the satisfaction of the Administrator good cause as to why the account should not be closed. (d) Account identification. The Administrator will assign a unique identifying number to each account established under paragraphs (a) through (c) of this section. (e) Responsibilities of authorized account representative and alternate authorized account representative **.** After the

est ablishment of a compliance account or general account, the Administrator will accept or act on a submission pertaining tothe account, including, but not limited to, submissions concerning the deduction or transfer of ERCs in the account, only if the submi ssion has been made, signed, and certified in accordance with § 62.16490(a) and §62.16510 or paragraphs (c)(2)(ii) and (5) of this section. (f) ERC identification information. The Administrator will assign to each ERC issued in the EPA ERC tracking system a unique serial identifier that beings with the two digit postal abbreviation of the S tate in which it was issued and includes the year it was issued, and the eligible resource category that generated it. (g) Records supporting ERC issuance. The Administrator will maintain in the EPA ERC tracking system records of, for each ERC, all of the following: (1) Account holder names and information ; (2) Authorized account representative name and information ; (3) Qualifying eligible resource identifi cation number,

name, 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 qualify ing eligible resource commenced generation or saving of energy ; (6) Individual ERCs, each with a unique serial identifierthat meets the requirements of paragraph (f) of this section ; (7) Records of ERC transfers among accounts, including the date of trans fer and the accounts involved in the transfer ; (8) The date an ERC was surrendered for a compliance demonstration ; (9) Date an ERC was retired by the regulatory body ; and (10) Each eligibility application, EM&V plan, M&V report, and verification report as sociated with the issuance of each specific ERC, and each regulatory approval and any documentation that supports the issuance of each ERC by the Administrator. (h) Access to records supporting ERC issuance. The Administrator will provide in the EPA ERC tr acking 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 minimu m, each eligible resource, affected EGU, eligible resource category, and
ERC. (i) Reports. The Administrator will provide in the EPA ERC tracking system electronic, internet

- based access to enable the generation of at least the following reports, [for as long as this regulation is effective] [in perpetuity]: (1) Account Activity Reports. By each account holder, reports based on records of their account activity, includingthe information listed in §62.16515(g) ; (2) Public Reports. By the public, reports that include: all of the information listed in §62.16515(g); a list of all registered account holders in the ERC tracking system, including compliance accounts and general accounts; a list of all ERC resources (including access to all documentation for suc h eligible resources); a list of all accredited independent verifiers; and aggregate ERC activity statistics on at least an annual basis, for at least the following: issuance of ERCs, transfers among accounts, transfers in or out of the ERC tracking system to/from another approved ERC tracking system (if relevant), and ERC retirements. The ERC tracking system shall provide this functionality for as long as this regulation is effective ; and (3) EPA reports. For the EPA and state regulators, the information l isted in §62.16515(g) and any other information regarding ERC issuance, transfer, surrender, and retirement for purpose of compliance with this regulation. (j) Interactions with other ERC tracking systems. If approved in connection with a S tate plan, then a n ERC tracking system may provide for transfers of ERCs to/from another ERC tracking system approved in connection with s S tate plan by the EPA, or provide for transfers of ERCs to/from an EPA

administered ERC tracking system used to administer a federalp lan. 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 author ized account representative seeking recordation of an ERC transfer shall submit the transfer to the Administrator. (b) An ERC transfer shall be correctly submitted if: (1) The transfer includes the following elements, in a format prescribed by the Administ rator: (i) The account numbers established by the Administrator for both the transferor and transferee accounts; (ii) The serial number of each ERC that is in the transferor account and is to be transferred; and (iii) The name and signature of the authorized account representative of the transferor account and the date signed; and (2) When the Administrator attempts to record the transfer, the transferor account includes each ERC identified by serial number in the transfer. **§ §**  **62.16530 When will ERC transfers be recorded?**  (a) Except as provided in paragraph (b) of this section,

w ithin five business days of receiving an ERC transfer that iscorrectly submitted under §62.16525, the Administrator will record an ERC transfer by mov ing 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 in cludes 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 befor e 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 s ection, 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 n otify the authorized account representatives of both accounts subject to the transfer of: (1) A decision not to record the transfer ; and (2) The reasons for such non

- recordation.**§62.16535 How will deductions for compliance with a 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 li sted in paragraphs (a) through ( f ) of this section. (a) Availability for deduction for compliance. ERCs are available to be deducted from a compliance account and used for compliance with an affected EGU’s CO 2 emissions standard for a compliance period on ly if the ERCs: (1) Were allocated for a year in such compliance period or a prior compliance period; and (2) Are held in the affected EGU's compliance account as of the allowance transfer deadline for such compliance period. (b) Deductions for compliance. After the recordation, in accordance with §62.16530, of ERC transfers submitted by the ERC transfer deadline for a compliance period, the Administrator will deduct from each affected EGU's compliance account ERCs available under paragraph (a) of this sect ion 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 theaffected EGU’ s CO 2 emission rate to equal 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 account. (c) Identification of ERCs by serial number. The authorized account representative for an affected EGU's compliance account may request that specific ERCs, identified by serial number, in the compliance account be deducted for emissions or excess emissions for a compliance period in accordance with paragraph (b) or ( e ) of this section. In order to be complete, such request shall 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 complia nce 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
ERCs of the affected EGU's excess emissions. ( f ) Recordation of deductions. The Administrator will record in the appropriate compliance account all deductions from such an account under paragraphs (b) and ( e ) of this s ection. **§ §**  **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 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 §62.165 70) 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 valid data; and (ii) The corresponding hour ly 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, maintain, and calibrate a CO 2 continuous emiss ions 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 di rect measurement of CO 2 concentration, the owner or operator of an affected EGU may use data from acertified 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 you must also install, certify, operate, maintain, and calibrate a continuous moisture monitoring system, according to § 75.11(b) of this chapter. Alternatively, you may either use an appropriate fuel

- specific default moisture value from §75.11(b) or submit a petition to the Administrator under §75.66 of this chapter for a site

- specific default moisture value (ii) For each “valid operating hour”, calculate the hourly
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). (iii) Next, multiply each hourly CO 2 mass emission rate by the affected EGU or stack operating time in hours (as defined in §72.2 of this chapter), to convert it to tons of 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 calculate the hourly CO 2 mass emissions.(v ) Sum all of the hourly CO 2 mass emissions values that were calculated according to procedures specified in paragraph (a)(3)(ii) of this section over the entire compliance period. (vi) For each continuous monitoring system used to determine the 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 described in section 7.6.5 of Appendix A to part 75 of this chapter to the exhaust gas flow rate data. (4) The owner or operator of an affected EGU that exclusively combusts liquid fuel and/or gaseous fuel may, as an alternative to complying with paragraph (a)(3) of this section, determine the hourly CO 2 m ass emissions according to paragraphs (a)(4)(i) through (vi) of this section. (i) Implement the applicable procedures in appendix D to part 75 of this chapter to determine hourly affected EGU heat input rates (MMBtu/h), based on hourly measurements of fue l flow rate and periodic determinations of the gross calorific value (GCV) of each fuel combusted.(ii) For each measured hourly heat input rate, use Equation
G

- 4 in Appendix G to part 75 of this chapter to calculate the hourly CO 2 mass emission rate (tons /hr). (iii) For each valid operating hour (as defined in paragraph (a)(2) of this section, determine the hourly CO 2 mass emission rate ( tons/hr) using the procedures specified in paragraph (a)(4)(ii) of this section and multiply it by the affected EGU or stack operating time in hours (as defined in §72.2 of this chapter), to convert to tons of CO 2 . Then, multiply the result by 2000 lb/ton to convert 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 calculate the hourly CO 2 mass emissions. (v) Sum all of the hourly CO 2 mass emissions values that were calculated according to procedures specified in paragraph (a)(4)(iii) of this section over the entire compliance period. (vi) The owner or operator of an affected EGU may determine site

- specific carbon

- based F

- factors (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 Equation G

- 4 nomenclature.(5) The owner or operator of an affected EGU must install, calibrate, maintain, and operate a sufficient number of watt meters to continuously measure and record on an hourly basis net electric output. Measurements must be performed using 0.2 accuracy class electricity metering instrumentation and calibration procedures as specified under ANSI Standards No. C12.20. Further, the owner or operator of an affected EGU that is a combined heat and power facility must install, calibrate, maintain and operate equipment to continuously measure and record on an hourly basis useful the rmal output and, if applicable, mechanical output, which are used with net electric output to determine net energy output. The owner or operator must calculate net energy output according to paragraph (a)(5)(i) of this section. (i) For each valid operating hour of a compliance period that was used in paragraph (a)(3) or (4) of this section to calculate the total CO 2 mass emissions, you must determine P net (the corresponding hourly net energy output in MWh) according to the procedures in paragraphs (a)(5)(i) (A) and (B) of this section, as appropriate for the type of affected EGU(s). For an operating hour in which a valid 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 stilldetermine 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 sec tion, but there is no (i.e., zero) gross electrical, mechanical, or useful thermal output, you must use that hour in the compliance determination. For hours or partial hours where the gross electric output is equal to or less than the auxiliary loads,

net electric output shall be counted as zero for this calculation. (A) Calculate 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 EGU or stack operating time.

PP

nnnnnn = ( 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 fo r 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 combustionturbine(s) in MWh. (Pe) IE = Electric energy output plus mechanical energy output (if any) of your affected EGU’s integrated equipment that provides electricity or mechanical energy to the affected EGU or auxiliary equipment in MWh. (Pe) A = Electric energy used for any auxiliary loads in MWh. (Pt) PS = Useful thermal output of steam (measured relative to SATP conditions, as applicable) that is used for applications that do not generate additional electricity, produce mechanical energy output, or enhance the performance of the affected EGU. This is calculated using the equation specified in paragraph (a)(5)(i) (B ) of this section in MWh. (Pt) HR = Non steam useful thermal output (measured relative to SATP conditions, as applicable) from h eat 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, producemechanical 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 l east on an annual basis 20.0 percent of the total net energy output consists of electric or direct mechanical output and 20.0 percent of the total net energy output consists of useful thermal output on a 12

- operating month rolling average basis, or 1.0 for all other affected
EGUs.

(B) If applicable to your affected EGU (for example, for combined heat and power), then you must calculate (Pt) PS using the following equation: ( 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 values 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 deter mine the CO 2 emission rate (lb/net MWh) for the compliance period. (ii) [Reserved]

(6) In accordance with §60.13(g), if two or more affected EGUs implementing the continuous emissions monitoring provisions in paragraph (a)(2) of this section share a common exhaust gas stack and are subject to the same emission standard, then the owner or operator may monitor 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 individualaffected 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)( 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 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. (8) If two or more affected EGUs serve a common electric generator, then you must apportion the combined hourly net

ener gy output to the individual affected EGUs according to the fraction of the total steam load contributed by each EGU. Alternatively, if the affected EGUs are identical, then you may apportion the combined hourly net electrical load to the individual EGUs ac cording 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. 16530, 62.16535, 62.16550, or 62.16565. **§ §**  **62.16 550**  **How does the Administrator process account errors?** The Administrator may, at his or her sole discretion and on his or her own motion, correct any error in any Allowance Tracking and Compliance System account. Within 10 business days of making such correction, the Administrator will notify the authorized account representative for the account. **§62.16555 What are my reporting, notification and**  **submission requirements?** (a) You must prepare and submit reports according to paragraphs (a) through ( g ) of this section, as applicable. (1) You must meet all applicable reporting requirements and submit reports as required under subpart G of part 75 of this chapter and you must include the following information , as applicable in the quarterly reports: (i) The percentage of valid operating hours in each quarter described 62.16540(a)(2) (i.e., the total number of validoperating hours) in that period divided by the total number of operating hours in that period, m ultiplied by 100 percent); (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 ne t 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; (v) The sum of the hourly net energy outpu t 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); (vii) The calculated C O 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 emust 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 monitori ng system has not been provisionally certified by the applicable date on which emissions data reporting is required to begin under paragraph (a) of this section, then the maximum (or in some cases, minimum) potential value for the parameter measured by the monitoring system shall be reported until the required certification testing is successfully completed, in accordance with §75.4(j) of this chapter, §75.37(b) of this chapter, or section 2.4 of appendix D to part 75 of this chapter (as applicable). Operat ing 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 representative of each affect ed EGU at the facility shall make all submissions required under the CO 2 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 requir ements 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 provid ed by the Clean Air Markets Division in the Office of Atmospheric Programs of

EPA. (e) For affected EGUs under this subpart that are not in the Acid Rain Program, you must also meet the reporting requirements and submit reports as required under subpart G of part 75 of this chapter, to the extent that those requirements and reports provide applicable data for the compliance demonstrations required under this subpart. (f) If your affected EGU captures CO 2 to meet the applicable emission standard, then you must report in accordance with the requirements of 40 CFR Part 98 Subpart PP and either: (1) Report in accordance with the requirements of 40 CFR Part 98 subpart RR, 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 98 subpart RR, if injection occurs off

- site. (g) You must prepare and submit notifications specified in§ 75.61 of this chapter, as applicable to your affected EGUs. **§ 62.16560 What ar**  **e my recordkeeping requirements?** (a) The owner or operator of each affected EGU must maintain the records, as described in (a)(1) of this section, for at least 5 years following the date of each compliance period, occurrence, measurement, maintenance, corr ective action, report, or record. (1) Unless otherwise provided, the owner or operator of an affected EGU must maintain the following records on site for at least 2 years after the date of each compliance period, compliance true

- up period, occurrence, meas urement, 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 certificate of representation under §62.16500 for the designated representative for each affected EGU and all documents that demonstrate the truth of the statements i n the certificate of representation; provided that the certificate and documents shall be retained on site at the affected EGU beyond such 5

- year period until such certificate of representation and documents are superseded because of the submission of a ne wcertificate of representation under §62.16500 changing the designated representative. (ii) All emissions monitoring information, in accordance with this subpart. (iii) Copies of all reports, compliance certifications, documents, data files, calculations and methods, other submissions and all records made or required under, or to demonstrate compliance with an affected EGU’s emission standard under § 62.16420 and any other requirements of the CO 2 Rate

- based Trading Program. ( iv ) Data that is required to be recorded by 40 CFR Part 75 Subpart F. ( v ) Data with respect to any ERCs generated by the affected EGU or used by the affected EGU in its compliance demonstration including the information in paragraphs ( a )( 1 )( v )(A) and (B) of this section. (A) All document s 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 do cumentation that supports the issuance of each ERC by the Administrator. (B) All records and reports relating to the surrender and retirement of ERCs for compliance with this regulation,including the date each individual ERC with a unique serial identific ation 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 adjustments of the information in the submission. (b) The Administrator may deduct ERCs from or transfer ERCs to a compliance account, based on the information in a submission, as adjusted under paragraph (a) of this section, and record such deductions and transfers. **Definitions §**  **62.16570 What definitions apply to this subpart?**  The terms used in this subpart shall have the meanings set forth in this section as follows: Acid Rain Program means a multi

- stat e 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 Protec tion Agency or the Director of the Clean AirMarkets Division (or its successor determined by the Administrator) of the United States Environmental Protection Agency, the Administrator's duly authorized representative under this subpart. Affected electric generating unit or Affected EGU means any steam generating unit, IGCC, or stationary combustion turbine that meets the applicability requirements in §§60.5840( b) and 60.5845 of this chapter. An affected EGU is not an eligible resource. Allowable 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

a llowances are allocated, recorded, held, deducted, or transferred only as whole ERCs
. Allowance system means a control program under which the owner or operator of each affected EGU is required to hold an authorization for each specified unit of carbon dioxide emitted from that facility during a specified period and which limitsthe 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. Alternate designated representative means, for a CO 2 Rate

based Trading affec ted 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 represen tative in matters pertaining to the CO 2 Rate

- based Trading Program. If the 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 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 t he 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.

APMP means [specify]

. Authorized account representative means, for a general account, the natural person who is authorized, in accordancewith 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 repr esentative. 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 outp ut signals from pollutant concentration monitors, flow monitors, diluent gas monitors, and other component parts of the monitoring system to produce a continuous record of the measured parameters in the measurement units required by this subpart. Base load rating means the maximum amount of heat input (fuel) that an EGU can combust on a steady state basis, as determined by the physical design and characteristics of the EGU at ISO conditions. For a stationary combustion turbine , base load rating includes the heat input from duct burners. Baseline means the electricity use that would have occurred without implementation of a specific EE measure. Biomass means biologically based material that is living or dead (e.g., trees, crops, grasses, tree litter, roots) above and belowground, and available on a renewable or recurring basis. Materials that are biologically based include non

- fossilized, biodegradable organic material originating from modern orcontemporarily grown plants, animals, or microorganisms (includi ng plants, products, byproducts and residues from agriculture, forestry, and related activities and industries, as well as the non

- fossilized and biodegradable organic fractions of industrial and municipal wastes, including gases and liquids recovered from the decomposition of non

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

- or other

- fuel

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

aside, the ratio of the net electrical energy produced by a generating unit for the period of time considered to the electrical energy that co uld 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 busi ness function or any other person who performs similar policy

- or decision

- making functions for the corporation; (2) For a partnership or sole proprietorship, a general partner or the proprietor respectively; or(3) For a local government entity or State, federal, or other public agency, a principal executive officer or ranking elected official. Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et
seq . 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 EGU 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 accordan ce with this subpart and subpart UUUU of part 60 of this chapter (including such a program that is revised in a State

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. S ynthetic 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 definiti on for thepurposes 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. Combined cycle unit means an electric generating unit that

uses a stationary combustion turbine from which the heat from the turbine exhaust gases is recovered by a heat recovery steam generating unit to generate additional electricity. Combined heat and power unit or CHP unit, (also known as “cogeneration”) means an ele ctric generating unit that use a

steam

- generating unit or stationary combustion turbine to simultaneously produce both electric (or mechanical) and useful thermal output from the same primary energy affected EGU. Common practice baseline or CPB means a bas eline 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

con sumer/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 sing le 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 a ffected 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. Complian ce period means the multi

- year periods starting January 1 of the first calendar year of the period, except as provided in §62.16420(c)(3), and ending on December 31 of the last calendar year, inclusive: (1) Compliance Period 1 means the period of 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 Period 3 means the period of two calendar years from January 1, 2028 to December 31, 2029. Continuous emission monitoring system or CEMS means the equipment required under this subpart to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes and using an automated data acquisition and handling system (DAHS), a permanent record of CO 2 emissions, stack gas volumetric flow rate, stack gas moisture content, andO 2 concentration (as applicable), in a manner consistent with part 75 of this chapter and § 62.16540(a)(3)

. The following systems are the principal types of continuous emission monitoring systems: (1) A flow monitoring system, consisting of a stack flow rate monitor and an automated data acquisition and handling system and providing a permanent, continuous record o f 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 poll utant 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 syste ms, bounded by interconnection metering and telemetry, capable ofcontrolling generation to maintain its interchange schedule with other control areas and contributing to frequency regulation of the interconnection. Deemed savings means estimates of average annual electricity savings for a single unit of an installed demand

side EE measure that (a) has been developed from data sources (such as prior metering studies) and analytical methods widely considered acceptable for the measure and (b) is applic able 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 actu al 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 syst ems are used in different building types or market segments. Demand

- side e nergy e fficiency or demand

- side EE means energy efficiency projects, programs or measures resulting in electricity savings.

Derate means a decrease in the available capacity of an

e lectric generating unit, due to a system or equipmentmodification 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 who is authorized by the owners and operators of the affected EGU and all such affected EGUs at the affected EGU, in accordance with this subpart, to represent a nd legally bind each owner and operator in matters pertaining to the CO 2 Rate

- based Trading Program. 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 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 Amer ican 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). 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

c hange in electricity use resulting from the implementation of d emand

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

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

. EM&V plan means 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 bemeasured, 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 th e affected EGU or affected EGU is required to measure, record, and report such air pollutants in accordance with this subpart, in accordance with part 75 of this chapter. Emission Rate Credit or ERC means a tradable compliance instrument that meets the req uirements of § 60.5790(c) of this chapter. ERC deduction or deduct ERCs means the permanent withdrawal of ERCs by the Administrator from a compliance account ( e.g. , in order to account for compliance with the applicable CO 2 emission standard). 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 c orrectly submitted, but not yet recorded, ERC transfer in accordance with this subpart; and (2) Have not been transferred out of the account by a correctly submitted, but not yet recorded, ERC transfer in accordance with this subpart.ERC transfer deadline means, for a compliance period in a given year, midnight of November 1 (if it is a business day), or midnight of the first business day thereafter (if November 1 is not a business day), immediately after such compliance period and is the deadline by which an ERC transfer must be submitted for recordation in a affected EGU's compliance account in order to be available for use in complying with the affected EGU's CO 2 emission standard for such compliance period in accordance with §§62.16420 and 62.16535. Essential generating characteristics means any characteristic that affects the eligibility of the qualifying energy generating resource for generating ERCs pursuant to this regulation, including the type of resource. Excess emissions means any ton of emiss ions from the affected EGUs at 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 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 or expanded in the future,in accordance with established plans. An existing state program, requirement, or measure may have past, current, and future impacts on EGU 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”, “s tationary source”, or “source” as set forth and implemented in a title V operating permit program or any other program under the Clean Air Act. Final period means the period that begins on January 1, 2030 and continues thereafter. The final period is compr ised 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 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. Fossil fuel means natural gas, petroleum, coal, and any form of solid, liquid, or gaseous fue l derived from such material for the purpose of creating useful heat.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. General account means an Allowance Tracking and Compliance System account established under this subpart that is not a compliance account.
Generator means a device that produces electricity. Gross electrical output means, for an affected EGU, electricity made available for use, including any such electricity used in the power production process (which process includes, but is not limited to, any on

- site processing or treatment of fuel combusted at the affected EGU and any on

- site emission controls).
GS

- ERC means an ERC issued to, but which may not be used for compliance by, an affected EGU that is a stationary combustion turbine. Aside from this restriction on use for compliance, GS

- ERCs are subject to all other provisions of this subpart related to ERCs. Heat input means, for an affected EGU for a specified period of tim e, the product (in mmBtu/time) of the grosscalorific value of the fuel (in mmBtu/lb) fed into the affected EGU multiplied by the fuel feed rate (in lb of fuel/time), as measured, recorded, and reported to the Administrator by the designated representative and as modified by the Administrator in accordance with this subpart and excluding the heat derived from preheated combustion air, recirculated flue gases, or exhaust. Heat input rate means, for an affected EGU, the amount of heat input (in mmBtu) divided by affected EGU operating time (in hr) or, for an affected EGU and a specific fuel, the amount of heat input attributed to the fuel (in mmBtu) divided by the affected EGU operating time (in hr) during which the affected EGU combusts the fuel.

Heat rate me ans, 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 or HRSG means a unit in which hot exhaust gas es from the combustion turbine engine are routed in order to extract heat from the gases and generate useful output. Heat recovery steam generating units can be used with or without duct burners. Indian country means “Indian country” as defined in 18
U.S.C . 1151. Integrated gasification combined cycle facility or IGCCfacility 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 int egrated 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, s tartup 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 as a liquid at ISO conditions and includes, but is not limited to, distillate oil and residual oil. 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 theinitial 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 affe cted facility. Mechanical energy measured in horsepower hour should be converted into MWh by multiplying it by 745.7 then dividing by 1,000,000. Monitoring system means any monitoring system that meets the requirements of this subpart, including a continuo us 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 M We, rounded to the nearest tenth) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings) as of such installation as specified by the manufacturer of the genera tor or, starting from the completion of any subsequent physical change in the generator resulting in an increase in the maximum electrical generating output that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings), such increased maximum amount (in MWe, roundedto 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 gaseou s state under ISO conditions. In addition, natural gas contains 20.0 grains or less of total sulfur per 100 standard cubic feet. Finally, natural gas does not include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast fu rnace 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.

Net

- electric output means the amount of gross generation the generator(s) produce (in cluding, 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 equipmen t, pumps, fans, pollution control equipment, other electricity needs, and transformer losses as measured at the transmission side of the step up transformer (e.g., the point of sale). Net energy output means:(1) The net electric or mechanical output from the affected facility, plus 100 percent of the useful thermal output measured relative to SATP conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the affected EGU (e.g., steam delivered to an i ndustrial process for a heating application). (2) For combined heat and power facilities where at least 20.0 percent of the total net energy output consists of electric or direct mechanical output and at least 20.0 percent of the total net energy output co nsists of useful thermal output on a
12

- operating month rolling average basis, the net electric or mechanical output from the affected EGU divided by 0.95, plus 100 percent of the useful thermal output; (e.g., steam delivered to an industrial process for a heating application). Net Summer Capacity means the maximum output, commonly expressed in megawatts (MW), that generating equipment can supply to system load, as demonstrated by a multi

- hour test, at the time of summer peak demand (period of June 1 throug h 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 whooperates, controls, or supervises an affected EGU at the affected EGU or the affected EGU and shall include, but not be limited to, any holding company, utility system, or plant manager of s uch affected EGU or affected EGU.
Owner means, for a CO 2 Rate

- based Trading affected EGU or an affected EGU at a affected EGU respectively, any of the following persons: (1) Any holder of any portion of the legal or equitable title in an affected EGU at th e 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 aff ected EGU under a life

- of

- the

- unit, firm power contractual arrangement. Permanently retired means, with regard to an affected EGU, an affected EGU that is unavailable for service and for which the affected EGU's owners and operators (1) have taken on as enforceable obligations in the operating permit that covers the affected EGU the conditions of 62.16415, or (2) rescinded orotherwise 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 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 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 magnitude of random error can be quantified based on the variat ions 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 indicate d in an official log, or by a notation made on the document, information, or correspondence, by the Administrator in the regular course of business.Recordation , record , or recorded means, with regard to ERCs, the moving of ERCs by the Administrator into, out of, or between Allowance Tracking and Compliance System accounts, for purposes of allocation, transfer, or deduction. Reference method means any direct test method of sampling and analyzing for an air pollutant as specified in §75.22 of this chapter. Replacement , replace , or replaced means, with regard to an affected EGU, the demolishing of an affected EGU, or the permanent retirement and permanent disabling of an affected EGU, and the construction of another affected EGU (the replacement affected EGU) to be used instead of the demolished or retired affected EGU (the replaced affected EGU). Solid fuel means 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 condit ions. This includes, but is not limited to, coal, biomass, and pulverized solid fuels. Solid waste incineration unit means a stationary, fossil

fuel

- fired boiler or stationary, fossil

- fuel

- fired combustion turbine that is a “solid waste incineration unit” as defined in section 129(g)(1) of the Clean Air Act. Systematic error means inaccuracies in the same direction, causing electricity savings values to be consistently eitheroverestimated or underestimated, and may result from factors such as incorrect as sumptions, a methodological issue, or a flawed reporting system. Standard ambient temperature 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 S tate , with the legal authority of the S tate . State measures means measures that the 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 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 emissions control technology, and any ancillary components and sub

components comprising any simple cycle stationary combustion turbine, any co mbined 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 orauxiliary equipment. Stationary means that the combustion turbine is not self

- propelled or intended to be propelled while performing its function. It may, however, be mounted on a vehicle for portability. If a stationary combustion turbine burns any solid fuel directly then it is considered a steam generating unit. Steam generating unit means any furnace, boiler, or other device used for combusting fuel and producing steam (nuclear steam generators are not included) plus any integrated equipment that provides electricity or u seful 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 St ates Postal Service; or (3) By other means of dispatch or transmission and delivery; (4) Provided that compliance with any “submission” or “service” deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt. Transmission and distribution loss means the difference between the quantity of electricity that serves a load (measured at the busbar of the generator) and the actual electricity useat the final distribution location (measured at the on

- site meter). Unit operating day means, with regard to an affected EGU, a calendar day in which the affected EGU combusts any fuel. Unit operating hour or hour of unit operation means, with regard to an affected EGU, an hour in which the affected EGU combusts any fuel. Uprate means 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 u seful 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 o utput 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 t hermal output. Utility power distribution system means the portion of an electricity grid owned or operated by a utility and dedicated to delivering electricity to customers. Valid data means quality

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

- assured data are reported un der 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, an d 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 f or 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). Verificatio n report means a report that meets the requirements of § 62.16465. Waste to Energy (WTE) means a process or unit (e.g., solid waste incineration unit) that recovers energy from the conversion or combustion of waste stream materials, such as municipal solid waste, to generate electricity and/or heat. **§62.16575 Measurements, abbreviations, and acronyms.** The measurements, abbreviations, and acronyms used in this subpart are defined as follows:

ADR

- alternated designated representative

Btu

— British thermal unit
CPP

— clean power plan
CO 2 — carbon dioxide
COI

— conflict of interest

DR

- designated representative

EE

— energy efficiency
EGU

- electric generating unit

EM&V

- evaluation, measurement, and verificationGCV

- gross calorific value
GJ

- giga joule

H 2 O

— water hr

— hour kg

- kilogramkW

— kilowatt electrical kWh

— kilowatt hour lb

— pound

M&V

– measurement and verification

mmBtu

—million Btu

MWe

— megawatt electrical MWh

— megawatt hour
O 2 — oxygen
yr — year

**Table 1 to Subpart NNN of Part 62 —**  **CO 2**  **Emission Standards (Pounds**  **of CO 2**  **Per Net MWh) T** 

**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 .32(2025

- 2027) Compliance Period 3 (2028

- 2029) .28 Final Compliance Period s .26

* * * * *
**PART 78**  **-- APPEAL PROCEDURES**  6 . The authority citation for Part 78 continues to read as follows: **Authority:** 42 U.S.C. 7401 et seq.
7 . Section 78.1 .27 is amended as follow: a. by r evis ing paragraphs (a)(1) ; and b. by add ing 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 ap proved under §51.123(o)(1) or (2) of this chapter, subparts AAA through III of part 96 of this chapter or State regulations approved under §51.124(o)(1) or (2) of this chapter, subparts AAAA through IIII of part 96 of this chapter or State regulations appr oved under §51.123(aa)(1) or (2) of this chapter, part 97 of this chapter, or subpart RR of part 98; 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 compa rable provisions in State regulations approved under §51.123(o)(1) or (2) of this chapter, §51.124(o)(1) or (2) of this chapter, and §51.123(aa)(1) or (2) of this chapter, respectively.

* * * * * (b) * * * (16) 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 th is chapter. (iv) The decision on the deduction 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 deduction 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) 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 indepen dent 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 §62.16 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.