SB 876

            
2020 SESSION

20104098D

SENATE BILL NO. 876


Offered January 8, 2020


Prefiled January 8, 2020

A BILL to amend and reenact �� 
 56-585.1, 56-585.2, 56-594, and 56-594.2 of the Code of 
 Virginia and to amend the Code of Virginia by 
 adding in Title 56 a chapter numbered 29, consisting of sections numbered 
 56-614 through 56-617, relating to the generation of electricity from sources 
 that do not emit carbon dioxide; clean energy standard.
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Patron-- Marsden

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Referred to Committee on Commerce and Labor

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Be it enacted by the General Assembly of Virginia:
 
 
1. That �� 56-585.1, 56-585.2, 56-594, and 56-594.2 of the 
 Code of Virginia are amended and reenacted and that the Code of Virginia is 
 amended by adding in Title 56 a chapter numbered 29, consisting of sections 
 numbered 56-614 through 56-617, as follows:
 
 
� 56-585.1. Generation, distribution, and transmission rates 
 after capped rates terminate or expire.
 
 
A. During the first six months of 2009, the Commission shall, 
 after notice and opportunity for hearing, initiate proceedings to review the 
 rates, terms and conditions for the provision of generation, distribution and 
 transmission services of each investor-owned incumbent electric utility. Such 
 proceedings shall be governed by the provisions of Chapter 10 (� 56-232 et 
 seq.), except as modified herein. In such proceedings the Commission shall 
 determine fair rates of return on common equity applicable to the generation 
 and distribution services of the utility. In so doing, the Commission may use 
 any methodology to determine such return it finds consistent with the public 
 interest, but such return shall not be set lower than the average of the 
 returns on common equity reported to the Securities and Exchange Commission for 
 the three most recent annual periods for which such data are available by not 
 less than a majority, selected by the Commission as specified in subdivision 2 
 b, of other investor-owned electric utilities in the peer group of the utility, 
 nor shall the Commission set such return more than 300 basis points higher than 
 such average. The peer group of the utility shall be determined in the manner 
 prescribed in subdivision 2 b. The Commission may increase or decrease such 
 combined rate of return by up to 100 basis points based on the generating plant 
 performance, customer service, and operating efficiency of a utility, as 
 compared to nationally recognized standards determined by the Commission to be 
 appropriate for such purposes. In such a proceeding, the Commission shall 
 determine the rates that the utility may charge until such rates are adjusted. 
 If the Commission finds that the utilitys combined rate of return on common 
 equity is more than 50 basis points below the combined rate of return as so 
 determined, it shall be authorized to order increases to the utilitys rates 
 necessary to provide the opportunity to fully recover the costs of providing 
 the utilitys services and to earn not less than such combined rate of return. 
 If the Commission finds that the utilitys combined rate of return on common 
 equity is more than 50 basis points above the combined rate of return as so 
 determined, it shall be authorized either (i) to order reductions to the 
 utilitys rates it finds appropriate, provided that the Commission may not 
 order such rate reduction unless it finds that the resulting rates will provide 
 the utility with the opportunity to fully recover its costs of providing its 
 services and to earn not less than the fair rates of return on common equity 
 applicable to the generation and distribution services; or (ii) to direct that 
 60 percent of the amount of the utilitys earnings that were more than 50 basis 
 points above the fair combined rate of return for calendar year 2008 be 
 credited to customers bills, in which event such credits shall be amortized 
 over a period of six to 12 months, as determined at the discretion of the 
 Commission, following the effective date of the Commissions order and be 
 allocated among customer classes such that the relationship between the 
 specific customer class rates of return to the overall target rate of return 
 will have the same relationship as the last approved allocation of revenues 
 used to design base rates. Commencing in 2011, the Commission, after notice and 
 opportunity for hearing, shall conduct reviews of the rates, terms and 
 conditions for the provision of generation, distribution and transmission 
 services by each investor-owned incumbent electric utility, subject to the 
 following provisions:
 
 
1. Rates, terms and conditions for each service shall be 
 reviewed separately on an unbundled basis, and such reviews shall be conducted 
 in a single, combined proceeding. Pursuant to subsection A of � 56-585.1:1, the 
 Commission shall conduct a review for a Phase I Utility in 2020, utilizing the 
 three successive 12-month test periods beginning January 1, 2017, and ending 
 December 31, 2019. Thereafter, reviews for a Phase I Utility will be on a 
 triennial basis with subsequent proceedings utilizing the three successive 
 12-month test periods ending December 31 immediately preceding the year in 
 which such review proceeding is conducted. Pursuant to subsection A of � 
 56-585.1:1, the Commission shall conduct a review for a Phase II Utility in 
 2021, utilizing the four successive 12-month test periods beginning January 1, 
 2017, and ending December 31, 2020, with subsequent reviews on a triennial 
 basis utilizing the three successive 12-month test periods ending December 31 
 immediately preceding the year in which such review proceeding is conducted. 
 All such reviews occurring after December 31, 2017, shall be referred to as 
 triennial reviews. For purposes of this section, a Phase I Utility is an 
 investor-owned incumbent electric utility that was, as of July 1, 1999, not 
 bound by a rate case settlement adopted by the Commission that extended in its 
 application beyond January 1, 2002, and a Phase II Utility is an investor-owned 
 incumbent electric utility that was bound by such a settlement.
 
 
2. Subject to the provisions of subdivision 6, the fair rate 
 of return on common equity applicable separately to the generation and 
 distribution services of such utility, and for the two such services combined, 
 and for any rate adjustment clauses approved under subdivision 5 or 6, shall be 
 determined by the Commission during each such triennial review, as follows:
 
 
a. The Commission may use any methodology to determine such 
 return it finds consistent with the public interest, but such return shall not 
 be set lower than the average of the returns on common equity reported to the 
 Securities and Exchange Commission for the three most recent annual periods for 
 which such data are available by not less than a majority, selected by the 
 Commission as specified in subdivision 2 b, of other investor-owned electric 
 utilities in the peer group of the utility subject to such triennial review, 
 nor shall the Commission set such return more than 300 basis points higher than 
 such average.
 
 
b. In selecting such majority of peer group investor-owned 
 electric utilities, the Commission shall first remove from such group the two 
 utilities within such group that have the lowest reported returns of the group, 
 as well as the two utilities within such group that have the highest reported 
 returns of the group, and the Commission shall then select a majority of the 
 utilities remaining in such peer group. In its final order regarding such 
 triennial review, the Commission shall identify the utilities in such peer 
 group it selected for the calculation of such limitation. For purposes of this 
 subdivision, an investor-owned electric utility shall be deemed part of such 
 peer group if (i) its principal operations are conducted in the southeastern 
 United States east of the Mississippi River in either the states of West 
 Virginia or Kentucky or in those states south of Virginia, excluding the state 
 of Tennessee, (ii) it is a vertically-integrated electric utility providing 
 generation, transmission and distribution services whose facilities and 
 operations are subject to state public utility regulation in the state where 
 its principal operations are conducted, (iii) it had a long-term bond rating 
 assigned by Moodys Investors Service of at least Baa at the end of the most 
 recent test period subject to such triennial review, and (iv) it is not an 
 affiliate of the utility subject to such triennial review.
 
 
c. The Commission may, consistent with its precedent for incumbent 
 electric utilities prior to the enactment of Chapters 888 and 933 of the Acts 
 of Assembly of 2007, increase or decrease the utilitys combined rate of return 
 based on the Commissions consideration of the utilitys performance.
 
 
d. In any Current Proceeding, the Commission shall determine 
 whether the Current Return has increased, on a percentage basis, above the 
 Initial Return by more than the increase, expressed as a percentage, in the 
 United States Average Consumer Price Index for all items, all urban consumers 
 (CPI-U), as published by the Bureau of Labor Statistics of the United States 
 Department of Labor, since the date on which the Commission determined the 
 Initial Return. If so, the Commission may conduct an additional analysis of 
 whether it is in the public interest to utilize such Current Return for the 
 Current Proceeding then pending. A finding of whether the Current Return 
 justifies such additional analysis shall be made without regard to any enhanced 
 rate of return on common equity awarded pursuant to the provisions of 
 subdivision 6. Such additional analysis shall include, but not be limited to, a 
 consideration of overall economic conditions, the level of interest rates and 
 cost of capital with respect to business and industry, in general, as well as 
 electric utilities, the current level of inflation and the utilitys cost of 
 goods and services, the effect on the utilitys ability to provide adequate 
 service and to attract capital if less than the Current Return were utilized 
 for the Current Proceeding then pending, and such other factors as the 
 Commission may deem relevant. If, as a result of such analysis, the Commission 
 finds that use of the Current Return for the Current Proceeding then pending 
 would not be in the public interest, then the lower limit imposed by 
 subdivision 2 a on the return to be determined by the Commission for such 
 utility shall be calculated, for that Current Proceeding only, by increasing 
 the Initial Return by a percentage at least equal to the increase, expressed as 
 a percentage, in the United States Average Consumer Price Index for all items, 
 all urban consumers (CPI-U), as published by the Bureau of Labor Statistics of 
 the United States Department of Labor, since the date on which the Commission 
 determined the Initial Return. For purposes of this subdivision:
 
 
"Current Proceeding" means any proceeding conducted 
 under any provisions of this subsection that require or authorize the 
 Commission to determine a fair combined rate of return on common equity for a 
 utility and that will be concluded after the date on which the Commission 
 determined the Initial Return for such utility.
 
 
"Current Return" means the minimum fair combined 
 rate of return on common equity required for any Current Proceeding by the 
 limitation regarding a utilitys peer group specified in subdivision 2 a.
 
 
"Initial Return" means the fair combined rate of 
 return on common equity determined for such utility by the Commission on the 
 first occasion after July 1, 2009, under any provision of this subsection pursuant 
 to the provisions of subdivision 2 a.
 
 
e. In addition to other considerations, in setting the return 
 on equity within the range allowed by this section, the Commission shall strive 
 to maintain costs of retail electric energy that are cost competitive with 
 costs of retail electric energy provided by the other peer group investor-owned 
 electric utilities.
 
 
f. The determination of such returns shall be made by the 
 Commission on a stand-alone basis, and specifically without regard to any 
 return on common equity or other matters determined with regard to facilities 
 described in subdivision 6.
 
 
g. If the combined rate of return on common equity earned by 
 the generation and distribution services is no more than 50 basis points above 
 or below the return as so determined or, for any test period commencing after 
 December 31, 2012, for a Phase II Utility and after December 31, 2013, for a 
 Phase I Utility, such return is no more than 70 basis points above or below the 
 return as so determined, such combined return shall not be considered either 
 excessive or insufficient, respectively. However, for any test period 
 commencing after December 31, 2012, for a Phase II Utility, and after December 
 31, 2013, for a Phase I Utility, if the utility has, during the test period or 
 periods under review, earned below the return as so determined, whether or not 
 such combined return is within 70 basis points of the return as so determined, 
 the utility may petition the Commission for approval of an increase in rates in 
 accordance with the provisions of subdivision 8 a as if it had earned more than 
 70 basis points below a fair combined rate of return, and such proceeding shall 
 otherwise be conducted in accordance with the provisions of this section. The 
 provisions of this subdivision are subject to the provisions of subdivision 8.
 
 
h. Any amount of a utilitys earnings directed by the 
 Commission to be credited to customers bills pursuant to this section shall 
 not be considered for the purpose of determining the utilitys earnings in any 
 subsequent triennial review.
 
 
3. Each such utility shall make a triennial filing by March 31 
 of every third year, with such filings commencing for a Phase I Utility in 
 2020, and such filings commencing for a Phase II Utility in 2021, consisting of 
 the schedules contained in the Commissions rules governing utility rate 
 increase applications. Such filing shall encompass the three successive 
 12-month test periods ending December 31 immediately preceding the year in 
 which such proceeding is conducted, except that the filing for a Phase II 
 Utility in 2021 shall encompass the four successive 12-month test periods 
 ending December 31, 2020, and in every such case the filing for each year shall 
 be identified separately and shall be segregated from any other year encompassed 
 by the filing. If the Commission determines that rates should be revised or 
 credits be applied to customers bills pursuant to subdivision 8 or 9, any rate 
 adjustment clauses previously implemented related to facilities utilizing 
 simple-cycle combustion turbines described in subdivision 6, shall be combined 
 with the utilitys costs, revenues and investments until the amounts that are 
 the subject of such rate adjustment clauses are fully recovered. The Commission 
 shall combine such clauses with the utilitys costs, revenues and investments 
 only after it makes its initial determination with regard to necessary rate 
 revisions or credits to customers bills, and the amounts thereof, but after 
 such clauses are combined as herein specified, they shall thereafter be 
 considered part of the utilitys costs, revenues, and investments for the 
 purposes of future triennial review proceedings. In a triennial filing under 
 this subdivision that does not result in an overall rate change a utility may 
 propose an adjustment to one or more tariffs that are revenue neutral to the 
 utility.
 
 
4. (Expires December 31, 2023) The following costs incurred by 
 the utility shall be deemed reasonable and prudent: (i) costs for transmission 
 services provided to the utility by the regional transmission entity of which 
 the utility is a member, as determined under applicable rates, terms and 
 conditions approved by the Federal Energy Regulatory Commission; (ii) costs 
 charged to the utility that are associated with demand response programs approved 
 by the Federal Energy Regulatory Commission and administered by the regional 
 transmission entity of which the utility is a member; and (iii) costs incurred 
 by the utility to construct, operate, and maintain transmission lines and 
 substations installed in order to provide service to a business park. Upon 
 petition of a utility at any time after the expiration or termination of capped 
 rates, but not more than once in any 12-month period, the Commission shall 
 approve a rate adjustment clause under which such costs, including, without 
 limitation, costs for transmission service; charges for new and existing 
 transmission facilities, including costs incurred by the utility to construct, 
 operate, and maintain transmission lines and substations installed in order to 
 provide service to a business park; administrative charges; and ancillary 
 service charges designed to recover transmission costs, shall be recovered on a 
 timely and current basis from customers. Retail rates to recover these costs 
 shall be designed using the appropriate billing determinants in the retail rate 
 schedules.
 
 
4. (Effective January 1, 2024) The following costs incurred by 
 the utility shall be deemed reasonable and prudent: (i) costs for transmission 
 services provided to the utility by the regional transmission entity of which 
 the utility is a member, as determined under applicable rates, terms and 
 conditions approved by the Federal Energy Regulatory Commission, and (ii) costs 
 charged to the utility that are associated with demand response programs 
 approved by the Federal Energy Regulatory Commission and administered by the 
 regional transmission entity of which the utility is a member. Upon petition of 
 a utility at any time after the expiration or termination of capped rates, but 
 not more than once in any 12-month period, the Commission shall approve a rate 
 adjustment clause under which such costs, including, without limitation, costs 
 for transmission service, charges for new and existing transmission facilities, 
 administrative charges, and ancillary service charges designed to recover 
 transmission costs, shall be recovered on a timely and current basis from 
 customers. Retail rates to recover these costs shall be designed using the 
 appropriate billing determinants in the retail rate schedules.
 
 
5. A utility may at any time, after the expiration or 
 termination of capped rates, but not more than once in any 12-month period, 
 petition the Commission for approval of one or more rate adjustment clauses for 
 the timely and current recovery from customers of the following costs:
 
 
a. Incremental costs described in clause (vi) of subsection B 
 of � 56-582 incurred between July 1, 2004, and the expiration or termination of 
 capped rates, if such utility is, as of July 1, 2007, deferring such costs 
 consistent with an order of the Commission entered under clause (vi) of 
 subsection B of � 56-582. The Commission shall approve such a petition allowing 
 the recovery of such costs that comply with the requirements of clause (vi) of 
 subsection B of � 56-582;
 
 
b. Projected and actual costs for the utility to design and 
 operate fair and effective peak-shaving programs. The Commission shall approve 
 such a petition if it finds that the program is in the public interest; 
 provided that the Commission shall allow the recovery of such costs as it finds 
 are reasonable;
 
 
c. Projected and actual costs for the utility to design, 
 implement, and operate energy efficiency programs, including a margin to be 
 recovered on operating expenses, which margin for the purposes of this section 
 shall be equal to the general rate of return on common equity determined as 
 described in subdivision 2. Any such petition shall include a proposed budget 
 for the design, implementation, and operation of the energy efficiency program. 
 The Commission shall only approve such a petition if it finds that the program 
 is in the public interest. If the Commission determines that an energy 
 efficiency program or portfolio of programs is not in the public interest, its 
 final order shall include all work product and analysis conducted by the 
 Commissions staff in relation to that program that has bearing upon the 
 Commissions determination. Such order shall adhere to existing protocols for 
 extraordinarily sensitive information. As part of such cost recovery, the 
 Commission, if requested by the utility, shall allow for the recovery of 
 revenue reductions related to energy efficiency programs. The Commission shall 
 only allow such recovery to the extent that the Commission determines such 
 revenue has not been recovered through margins from incremental off-system 
 sales as defined in � 56-249.6 that are directly attributable to energy 
 efficiency programs.
 
 
None of the costs of new energy efficiency programs of an electric 
 utility, including recovery of revenue reductions, shall be assigned to any 
 large general service customer. A large general service customer is a customer 
 that has a verifiable history of having used more than 500 kilowatts of demand 
 from a single meter of delivery. A utility shall not charge such large general 
 service customer, as defined by the Commission, for the costs of installing 
 energy efficiency equipment beyond what is required to provide electric service 
 and meter such service on the customers premises if the customer provides, at 
 the customers expense, equivalent energy efficiency equipment. In all relevant 
 proceedings pursuant to this section, the Commission shall take into 
 consideration the goals of economic development, energy efficiency and 
 environmental protection in the Commonwealth;
 
 
d. Projected and actual costs of participation in a renewable clean energy portfolio 
 standard program pursuant to � 56-585.2 that are not recoverable under 
 subdivision 6. The Commission shall approve such a petition allowing the 
 recovery of such costs as are provided for in a program approved pursuant to � 
 56-585.2;
 
 
e. Projected and actual costs of projects that the Commission 
 finds to be necessary to comply with state or federal environmental laws or regulations 
 applicable to generation facilities used to serve the utilitys native load 
 obligations. The Commission shall approve such a petition if it finds that such 
 costs are necessary to comply with such environmental laws or regulations; and
 
 
f. Projected and actual costs, not currently in rates, for the 
 utility to design, implement, and operate programs approved by the Commission 
 that accelerate the vegetation management of distribution rights-of-way. No 
 costs shall be allocated to or recovered from customers that are served within 
 the large general service rate classes for a Phase II Utility or that are 
 served at subtransmission or transmission voltage, or take delivery at a 
 substation served from subtransmission or transmission voltage, for a Phase I Utility.
 
 
Any rate adjustment clause approved under subdivision 5 c by 
 the Commission shall remain in effect until the utility exhausts the approved 
 budget for the energy efficiency program. The Commission shall have the 
 authority to determine the duration or amortization period for any other rate 
 adjustment clause approved under this subdivision.
 
 
6. To ensure the generation and delivery of a reliable and 
 adequate supply of electricity, to meet the utilitys projected native load 
 obligations and to promote economic development, a utility may at any time, 
 after the expiration or termination of capped rates, petition the Commission 
 for approval of a rate adjustment clause for recovery on a timely and current 
 basis from customers of the costs of (i) a coal-fueled generation facility that 
 utilizes Virginia coal and is located in the coalfield region of the 
 Commonwealth as described in � 15.2-6002, regardless of whether such facility 
 is located within or without the utilitys service territory, (ii) one or more 
 other generation facilities, (iii) one or more major unit modifications of 
 generation facilities, including the costs of any system or equipment upgrade, 
 system or equipment replacement, or other cost reasonably appropriate to extend 
 the combined operating license for or the operating life of one or more 
 generation facilities utilizing nuclear power, (iv) one or more new underground 
 facilities to replace one or more existing overhead distribution facilities of 
 69 kilovolts or less located within the Commonwealth, (v) one or more pumped 
 hydroelectricity generation and storage facilities that utilize on-site or 
 off-site renewable energy resources as all or a portion of their power source 
 and such facilities and associated resources are located in the coalfield region 
 of the Commonwealth as described in � 15.2-6002, regardless of whether such 
 facility is located within or without the utilitys service territory, or (vi) 
 one or more electric distribution grid transformation projects; however, 
 subject to the provisions of the following sentence, the utility shall not file 
 a petition under clause (iv) more often than annually and, in such petition, 
 shall not seek any annual incremental increase in the level of investments 
 associated with such a petition that exceeds five percent of such utilitys 
 distribution rate base, as such rate base was determined for the most recently 
 ended 12-month test period in the utilitys latest review proceeding conducted 
 pursuant to subdivision 3 and concluded by final order of the Commission prior 
 to the date of filing of such petition under clause (iv). In all proceedings 
 regarding petitions filed under clause (iv) or (vi), the level of investments 
 approved for recovery in such proceedings shall be in addition to, and not in 
 lieu of, levels of investments previously approved for recovery in prior 
 proceedings under clause (iv) or (vi), as applicable. As of December 1, 2028, 
 any costs recovered by a utility pursuant to clause (iv) shall be limited to 
 any remaining costs associated with conversions of overhead distribution 
 facilities to underground facilities that have been previously approved or are 
 pending approval by the Commission through a petition by the utility under this 
 subdivision. Such a petition concerning facilities described in clause (ii) 
 that utilize nuclear power, facilities described in clause (ii) that are 
 coal-fueled and will be built by a Phase I Utility, or facilities described in 
 clause (i) may also be filed before the expiration or termination of capped 
 rates. A utility that constructs or makes modifications to any such facility, 
 or purchases any facility consisting of at least one megawatt of generating 
 capacity using energy derived from sunlight and located in the Commonwealth and 
 that utilizes goods or services sourced, in whole or in part, from one or more 
 Virginia businesses, shall have the right to recover the costs of the facility, 
 as accrued against income, through its rates, including projected construction 
 work in progress, and any associated allowance for funds used during 
 construction, planning, development and construction or acquisition costs, 
 life-cycle costs, costs related to assessing the feasibility of potential sites 
 for new underground facilities, and costs of infrastructure associated 
 therewith, plus, as an incentive to undertake such projects, an enhanced rate 
 of return on common equity calculated as specified below; however, in 
 determining the amounts recoverable under a rate adjustment clause for new 
 underground facilities, the Commission shall not consider, or increase or 
 reduce such amounts recoverable because of (a) the operation and maintenance 
 costs attributable to either the overhead distribution facilities being 
 replaced or the new underground facilities or (b) any other costs attributable 
 to the overhead distribution facilities being replaced. Notwithstanding the 
 preceding sentence, the costs described in clauses (a) and (b) thereof shall 
 remain eligible for recovery from customers through the utilitys base rates 
 for distribution service. A utility filing a petition for approval to construct 
 or purchase a facility consisting of at least one megawatt of generating 
 capacity using energy derived from sunlight and located in the Commonwealth and 
 that utilizes goods or services sourced, in whole or in part, from one or more 
 Virginia businesses may propose a rate adjustment clause based on a market 
 index in lieu of a cost of service model for such facility. A utility seeking 
 approval to construct or purchase a generating facility described in clause (i) 
 or (ii) shall demonstrate that it has considered and weighed alternative 
 options, including third-party market alternatives, in its selection process. 
 The costs of the facility, other than return on projected construction work in 
 progress and allowance for funds used during construction, shall not be 
 recovered prior to the date a facility constructed by the utility and described 
 in clause (i), (ii), (iii) or (v) begins commercial operation, the date the 
 utility becomes the owner of a purchased generation facility consisting of at 
 least one megawatt of generating capacity using energy derived from sunlight 
 and located in the Commonwealth and that utilizes goods or services sourced, in 
 whole or in part, from one or more Virginia businesses, or the date new underground 
 facilities are classified by the utility as plant in service.
 
 
Such enhanced rate of return on common equity shall be applied 
 to allowance for funds used during construction and to construction work in 
 progress during the construction phase of the facility and shall thereafter be 
 applied to the entire facility during the first portion of the service life of 
 the facility. The first portion of the service life shall be as specified in 
 the table below; however, the Commission shall determine the duration of the 
 first portion of the service life of any facility, within the range specified 
 in the table below, which determination shall be consistent with the public 
 interest and shall reflect the Commissions determinations regarding how 
 critical the facility may be in meeting the energy needs of the citizens of the 
 Commonwealth and the risks involved in the development of the facility. After 
 the first portion of the service life of the facility is concluded, the 
 utilitys general rate of return shall be applied to such facility for the 
 remainder of its service life. As used herein, the service life of the facility 
 shall be deemed to begin on the date a facility constructed by the utility and 
 described in clause (i), (ii), (iii) or (v) begins commercial operation, the 
 date the utility becomes the owner of a purchased generation facility 
 consisting of at least one megawatt of generating capacity using energy derived 
 from sunlight and located in the Commonwealth and that utilizes goods or 
 services sourced, in whole or in part, from one or more Virginia businesses, or 
 the date new underground facilities or new electric distribution grid 
 transformation projects are classified by the utility as plant in service, and 
 such service life shall be deemed equal in years to the life of that facility 
 as used to calculate the utilitys depreciation expense. Such enhanced rate of 
 return on common equity shall be calculated by adding the basis points 
 specified in the table below to the utilitys general rate of return, and such 
 enhanced rate of return shall apply only to the facility that is the subject of 
 such rate adjustment clause. Allowance for funds used during construction shall 
 be calculated for any such facility utilizing the utilitys actual capital 
 structure and overall cost of capital, including an enhanced rate of return on 
 common equity as determined pursuant to this subdivision, until such 
 construction work in progress is included in rates. The construction of any 
 facility described in clause (i) or (v) is in the public interest, and in 
 determining whether to approve such facility, the Commission shall liberally 
 construe the provisions of this title. The construction or purchase by a 
 utility of one or more generation facilities with at least one megawatt of 
 generating capacity, and with an aggregate rated capacity that does not exceed 
 5,000 megawatts, including rooftop solar installations with a capacity of not 
 less than 50 kilowatts, and with an aggregate capacity of 50 megawatts, that 
 use energy derived from sunlight or from wind and are located in the 
 Commonwealth or off the Commonwealths Atlantic shoreline, regardless of 
 whether any of such facilities are located within or without the utilitys 
 service territory, is in the public interest, and in determining whether to 
 approve such facility, the Commission shall liberally construe the provisions 
 of this title. A utility may enter into short-term or long-term power purchase 
 contracts for the power derived from sunlight generated by such generation 
 facility prior to purchasing the generation facility. The replacement of any 
 subset of a utilitys existing overhead distribution tap lines that have, in 
 the aggregate, an average of nine or more total unplanned outage 
 events-per-mile over a preceding 10-year period with new underground facilities 
 in order to improve electric service reliability is in the public interest. In 
 determining whether to approve petitions for rate adjustment clauses for such 
 new underground facilities that meet this criteria, and in determining the 
 level of costs to be recovered thereunder, the Commission shall liberally 
 construe the provisions of this title.
 
 
The conversion of any such facilities on or after September 1, 
 2016, is deemed to provide local and system-wide benefits and to be cost beneficial, 
 and the costs associated with such new underground facilities are deemed to be 
 reasonably and prudently incurred and, notwithstanding the provisions of 
 subsection C or D, shall be approved for recovery by the Commission pursuant to 
 this subdivision, provided that the total costs associated with the replacement 
 of any subset of existing overhead distribution tap lines proposed by the 
 utility with new underground facilities, exclusive of financing costs, shall 
 not exceed an average cost per customer of $20,000, with such customers, 
 including those served directly by or downline of the tap lines proposed for 
 conversion, and, further, such total costs shall not exceed an average cost per 
 mile of tap lines converted, exclusive of financing costs, of $750,000. A 
 utility shall, without regard for whether it has petitioned for any rate 
 adjustment clause pursuant to clause (vi), petition the Commission, not more 
 than once annually, for approval of a plan for electric distribution grid 
 transformation projects. Any plan for electric distribution grid transformation 
 projects shall include both measures to facilitate integration of distributed 
 energy resources and measures to enhance physical electric distribution grid 
 reliability and security. In ruling upon such a petition, the Commission shall 
 consider whether the utilitys plan for such projects, and the projected costs 
 associated therewith, are reasonable and prudent. Such petition shall be 
 considered on a stand-alone basis without regard to the other costs, revenues, 
 investments, or earnings of the utility; without regard to whether the costs 
 associated with such projects will be recovered through a rate adjustment 
 clause under this subdivision or through the utilitys rates for generation and 
 distribution services; and without regard to whether such costs will be the 
 subject of a customer credit offset, as applicable, pursuant to subdivision 8 
 d. The Commissions final order regarding any such petition for approval of an 
 electric distribution grid transformation plan shall be entered by the 
 Commission not more than six months after the date of filing such petition. The 
 Commission shall likewise enter its final order with respect to any petition by 
 a utility for a certificate to construct and operate a generating facility or 
 facilities utilizing energy derived from sunlight, pursuant to subsection D of 
 � 56-580, within six months after the date of filing such petition. The basis 
 points to be added to the utilitys general rate of return to calculate the 
 enhanced rate of return on common equity, and the first portion of that 
 facilitys service life to which such enhanced rate of return shall be applied, 
 shall vary by type of facility, as specified in the following table:
 
 

  


 

 
 
 

 
Type of Generation Facility
 
 

 
Basis Points
 
 

 
First Portion of Service Life
 
 
 

 

 
 
 

 
Nuclear-powered
 
 

 
200
 
 

 
Between 12 and 25 years
 
 
 

 

 
 
 

 
Carbon capture compatible, clean-coal powered
 
 

 
200
 
 

 
Between 10 and 20 years
 
 
 

 

 
 
 

 
Renewable powered, other than landfill gas powered
 
 

 
200
 
 

 
Between 5 and 15 years
 
 
 

 

 
 
 

 
Coalbed methane gas powered
 
 

 
150
 
 

 
Between 5 and 15 years
 
 
 

 

 
 
 

 
Landfill gas powered
 
 

 
200
 
 

 
Between 5 and 15 years
 
 
 

 

 
 
 

 
Conventional coal or combined-cycle combustion turbine
 
 

 
100
 
 

 
Between 10 and 20 years
 
 
 
 
 
For generating facilities other than those utilizing nuclear 
 power constructed pursuant to clause (ii) or those utilizing energy derived 
 from offshore wind, as of July 1, 2013, only those facilities as to which a 
 rate adjustment clause under this subdivision has been previously approved by 
 the Commission, or as to which a petition for approval of such rate adjustment 
 clause was filed with the Commission, on or before January 1, 2013, shall be 
 entitled to the enhanced rate of return on common equity as specified in the 
 above table during the construction phase of the facility and the approved 
 first portion of its service life.
 
 
For generating facilities within the Commonwealth utilizing 
 nuclear power or those utilizing energy derived from offshore wind projects 
 located in waters off the Commonwealths Atlantic shoreline, such facilities 
 shall continue to be eligible for an enhanced rate of return on common equity 
 during the construction phase of the facility and the approved first portion of 
 its service life of between 12 and 25 years in the case of a facility utilizing 
 nuclear power and for a service life of between 5 and 15 years in the case of a 
 facility utilizing energy derived from offshore wind, provided, however, that, 
 as of July 1, 2013, the enhanced return for such facilities constructed 
 pursuant to clause (ii) shall be 100 basis points, which shall be added to the 
 utilitys general rate of return as determined under subdivision 2. Thirty 
 percent of all costs of such a facility utilizing nuclear power that the 
 utility incurred between July 1, 2007, and December 31, 2013, and all of such 
 costs incurred after December 31, 2013, may be deferred by the utility and 
 recovered through a rate adjustment clause under this subdivision at such time 
 as the Commission provides in an order approving such a rate adjustment clause. 
 The remaining 70 percent of all costs of such a facility that the utility 
 incurred between July 1, 2007, and December 31, 2013, shall not be deferred for 
 recovery through a rate adjustment clause under this subdivision; however, such 
 remaining 70 percent of all costs shall be recovered ratably through existing 
 base rates as determined by the Commission in the test periods under review in 
 the utilitys next review filed after July 1, 2014. Thirty percent of all costs 
 of such a facility utilizing energy derived from offshore wind that the utility 
 incurred between July 1, 2007, and December 31, 2013, and all of such costs 
 incurred after December 31, 2013, may be deferred by the utility and recovered 
 through a rate adjustment clause under this subdivision at such time as the 
 Commission provides in an order approving such a rate adjustment clause. The 
 remaining 70 percent of all costs of such a facility that the utility incurred 
 between July 1, 2007, and December 31, 2013, shall not be deferred for recovery 
 through a rate adjustment clause under this subdivision; however, such 
 remaining 70 percent of all costs shall be recovered ratably through existing 
 base rates as determined by the Commission in the test periods under review in 
 the utilitys next review filed after July 1, 2014.
 
 
In connection with planning to meet forecasted demand for 
 electric generation supply and assure the adequate and sufficient reliability 
 of service, consistent with � 56-598, planning and development activities for a 
 new nuclear generation facility or facilities are in the public interest.
 
 
In connection with planning to meet forecasted demand for 
 electric generation supply and assure the adequate and sufficient reliability 
 of service, consistent with � 56-598, planning and development activities for a 
 new utility-owned and utility-operated generating facility or facilities 
 utilizing energy derived from sunlight or from onshore or offshore wind are in 
 the public interest.
 
 
Construction, purchasing, or leasing activities for a new 
 utility-owned and utility-operated generating facility or facilities utilizing 
 energy derived from sunlight or from wind with an aggregate capacity of 5,000 
 megawatts, including rooftop solar installations with a capacity of not less 
 than 50 kilowatts, and with an aggregate capacity of 50 megawatts, together 
 with a new test or demonstration project for a utility-owned and 
 utility-operated generating facility or facilities utilizing energy derived 
 from offshore wind with an aggregate capacity of not more than 16 megawatts, 
 are in the public interest. To the extent that a utility elects to recover the 
 costs of any such new generation facility or facilities through its rates for 
 generation and distribution services and does not petition and receive approval 
 from the Commission for recovery of such costs through a rate adjustment clause 
 described in clause (ii), the Commission shall, upon the request of the utility 
 in a triennial review proceeding, provide for a customer credit reinvestment 
 offset, as applicable, pursuant to subdivision 8 d with respect to all costs 
 deemed reasonable and prudent by the Commission in a proceeding pursuant to 
 subsection D of � 56-580 or in a triennial review proceeding.
 
 
Electric distribution grid transformation projects are in the 
 public interest. To the extent that a utility elects to recover the costs of 
 such electric distribution grid transformation projects through its rates for 
 generation and distribution services, and does not petition and receive 
 approval from the Commission for recovery of such costs through a rate 
 adjustment clause described in clause (vi), the Commission shall, upon the 
 request of the utility in a triennial review proceeding, provide for a customer 
 credit reinvestment offset, as applicable, pursuant to subdivision 8 d with 
 respect to all costs deemed reasonable and prudent by the Commission in a 
 proceeding for approval of a plan for electric distribution grid transformation 
 projects pursuant to subdivision 6 or in a triennial review proceeding.
 
 
Neither generation facilities described in clause (ii) that 
 utilize simple-cycle combustion turbines nor new underground facilities shall 
 receive an enhanced rate of return on common equity as described herein, but 
 instead shall receive the utilitys general rate of return during the 
 construction phase of the facility and, thereafter, for the entire service life 
 of the facility. No rate adjustment clause for new underground facilities shall 
 allocate costs to, or provide for the recovery of costs from, customers that 
 are served within the large power service rate class for a Phase I Utility and 
 the large general service rate classes for a Phase II Utility. New underground 
 facilities are hereby declared to be ordinary extensions or improvements in the 
 usual course of business under the provisions of � 56-265.2.
 
 
As used in this subdivision, a generation facility is (1) 
 "coalbed methane gas powered" if the facility is fired at least 50 
 percent by coalbed methane gas, as such term is defined in � 45.1-361.1, 
 produced from wells located in the Commonwealth, and (2) "landfill gas 
 powered" if the facility is fired by methane or other combustible gas 
 produced by the anaerobic digestion or decomposition of biodegradable materials 
 in a solid waste management facility licensed by the Waste Management Board. A 
 landfill gas powered facility includes, in addition to the generation facility 
 itself, the equipment used in collecting, drying, treating, and compressing the 
 landfill gas and in transmitting the landfill gas from the solid waste 
 management facility where it is collected to the generation facility where it 
 is combusted.
 
 
For purposes of this subdivision, "general rate of 
 return" means the fair combined rate of return on common equity as it is 
 determined by the Commission for such utility pursuant to subdivision 2.
 
 
Notwithstanding any other provision of this subdivision, if 
 the Commission finds during the triennial review conducted for a Phase II 
 Utility in 2021 that such utility has not filed applications for all necessary 
 federal and state regulatory approvals to construct one or more nuclear-powered 
 or coal-fueled generation facilities that would add a total capacity of at 
 least 1500 megawatts to the amount of the utilitys generating resources as 
 such resources existed on July 1, 2007, or that, if all such approvals have 
 been received, that the utility has not made reasonable and good faith efforts 
 to construct one or more such facilities that will provide such additional 
 total capacity within a reasonable time after obtaining such approvals, then 
 the Commission, if it finds it in the public interest, may reduce on a 
 prospective basis any enhanced rate of return on common equity previously 
 applied to any such facility to no less than the general rate of return for 
 such utility and may apply no less than the utilitys general rate of return to 
 any such facility for which the utility seeks approval in the future under this 
 subdivision.
 
 
Notwithstanding any other provision of this subdivision, if a 
 Phase II utility obtains approval from the Commission of a rate adjustment 
 clause pursuant to subdivision 6 associated with a test or demonstration 
 project involving a generation facility utilizing energy from offshore wind, 
 and such utility has not, as of July 1, 2023, commenced construction as defined 
 for federal income tax purposes of an offshore wind generation facility or 
 facilities with a minimum aggregate capacity of 250 megawatts, then the 
 Commission, if it finds it in the public interest, may direct that the costs 
 associated with any such rate adjustment clause involving said test or 
 demonstration project shall thereafter no longer be recovered through a rate 
 adjustment clause pursuant to subdivision 6 and shall instead be recovered 
 through the utilitys rates for generation and distribution services, with no 
 change in such rates for generation and distribution services as a result of 
 the combination of such costs with the other costs, revenues, and investments 
 included in the utilitys rates for generation and distribution services. Any 
 such costs shall remain combined with the utilitys other costs, revenues, and 
 investments included in its rates for generation and distribution services 
 until such costs are fully recovered.
 
 
7. Any petition filed pursuant to subdivision 4, 5, or 6 shall 
 be considered by the Commission on a stand-alone basis without regard to the 
 other costs, revenues, investments, or earnings of the utility. Any costs 
 incurred by a utility prior to the filing of such petition, or during the 
 consideration thereof by the Commission, that are proposed for recovery in such 
 petition and that are related to subdivision 5 a, or that are related to 
 facilities and projects described in clause (i) of subdivision 6, or that are 
 related to new underground facilities described in clause (iv) of subdivision 
 6, shall be deferred on the books and records of the utility until the 
 Commissions final order in the matter, or until the implementation of any 
 applicable approved rate adjustment clauses, whichever is later. Except as 
 otherwise provided in subdivision 6, any costs prudently incurred on or after 
 July 1, 2007, by a utility prior to the filing of such petition, or during the 
 consideration thereof by the Commission, that are proposed for recovery in such 
 petition and that are related to facilities and projects described in clause 
 (ii) or clause (iii) of subdivision 6 that utilize nuclear power, or 
 coal-fueled facilities and projects described in clause (ii) of subdivision 6 
 if such coal-fueled facilities will be built by a Phase I Utility, shall be 
 deferred on the books and records of the utility until the Commissions final 
 order in the matter, or until the implementation of any applicable approved 
 rate adjustment clauses, whichever is later. Any costs prudently incurred after 
 the expiration or termination of capped rates related to other matters 
 described in subdivision 4, 5, or 6 shall be deferred beginning only upon the 
 expiration or termination of capped rates, provided, however, that no provision 
 of this act shall affect the rights of any parties with respect to the rulings 
 of the Federal Energy Regulatory Commission in PJM Interconnection LLC and 
 Virginia Electric and Power Company, 109 F.E.R.C. P 61,012 (2004). A utility 
 shall establish a regulatory asset for regulatory accounting and ratemaking 
 purposes under which it shall defer its operation and maintenance costs 
 incurred in connection with (i) the refueling of any nuclear-powered generating 
 plant and (ii) other work at such plant normally performed during a refueling 
 outage. The utility shall amortize such deferred costs over the refueling 
 cycle, but in no case more than 18 months, beginning with the month in which 
 such plant resumes operation after such refueling. The refueling cycle shall be 
 the applicable period of time between planned refueling outages for such plant. 
 As of January 1, 2014, such amortized costs are a component of base rates, 
 recoverable in base rates only ratably over the refueling cycle rather than 
 when such outages occur, and are the only nuclear refueling costs recoverable 
 in base rates. This provision shall apply to any nuclear-powered generating 
 plant refueling outage commencing after December 31, 2013, and the Commission 
 shall treat the deferred and amortized costs of such regulatory asset as part of 
 the utilitys costs for the purpose of proceedings conducted (a) with respect 
 to triennial filings under subdivision 3 made on and after July 1, 2014, and 
 (b) pursuant to � 56-245 or the Commissions rules governing utility rate 
 increase applications as provided in subsection B. This provision shall not be 
 deemed to change or reset base rates.
 
 
The Commissions final order regarding any petition filed 
 pursuant to subdivision 4, 5, or 6 shall be entered not more than three months, 
 eight months, and nine months, respectively, after the date of filing of such 
 petition. If such petition is approved, the order shall direct that the 
 applicable rate adjustment clause be applied to customers bills not more than 
 60 days after the date of the order, or upon the expiration or termination of 
 capped rates, whichever is later.
 
 
8. In any triennial review proceeding, for the purposes of 
 reviewing earnings on the utilitys rates for generation and distribution 
 services, the following utility generation and distribution costs not proposed 
 for recovery under any other subdivision of this subsection, as recorded per 
 books by the utility for financial reporting purposes and accrued against 
 income, shall be attributed to the test periods under review and deemed fully 
 recovered in the period recorded: costs associated with asset impairments 
 related to early retirement determinations made by the utility for utility 
 generation facilities fueled by coal, natural gas, or oil or for automated 
 meter reading electric distribution service meters; costs associated with 
 projects necessary to comply with state or federal environmental laws, 
 regulations, or judicial or administrative orders relating to coal combustion 
 by-product management that the utility does not petition to recover through a rate 
 adjustment clause pursuant to subdivision 5 e; costs associated with severe 
 weather events; and costs associated with natural disasters. Such costs shall 
 be deemed to have been recovered from customers through rates for generation 
 and distribution services in effect during the test periods under review unless 
 such costs, individually or in the aggregate, together with the utilitys other 
 costs, revenues, and investments to be recovered through rates for generation 
 and distribution services, result in the utilitys earned return on its 
 generation and distribution services for the combined test periods under review 
 to fall more than 50 basis points below the fair combined rate of return 
 authorized under subdivision 2 for such periods or, for any test period 
 commencing after December 31, 2012, for a Phase II Utility and after December 
 31, 2013, for a Phase I Utility, to fall more than 70 basis points below the 
 fair combined rate of return authorized under subdivision 2 for such periods. 
 In such cases, the Commission shall, in such triennial review proceeding, 
 authorize deferred recovery of such costs and allow the utility to amortize and 
 recover such deferred costs over future periods as determined by the 
 Commission. The aggregate amount of such deferred costs shall not exceed an 
 amount that would, together with the utilitys other costs, revenues, and 
 investments to be recovered through rates for generation and distribution 
 services, cause the utilitys earned return on its generation and distribution 
 services to exceed the fair rate of return authorized under subdivision 2, less 
 50 basis points, for the combined test periods under review or, for any test 
 period commencing after December 31, 2012, for a Phase II Utility and after 
 December 31, 2013, for a Phase I Utility, to exceed the fair rate of return 
 authorized under subdivision 2 less 70 basis points. Nothing in this section 
 shall limit the Commissions authority, pursuant to the provisions of Chapter 
 10 (� 56-232 et seq.), including specifically � 56-235.2, following the review 
 of combined test period earnings of the utility in a triennial review, for 
 normalization of nonrecurring test period costs and annualized adjustments for 
 future costs, in determining any appropriate increase or decrease in the utilitys 
 rates for generation and distribution services pursuant to subdivision 8 a or 8 
 c.
 
 
If the Commission determines as a result of such triennial 
 review that:
 
 
a. The utility has, during the test period or periods under 
 review, considered as a whole, earned more than 50 basis points below a fair 
 combined rate of return on its generation and distribution services or, for any 
 test period commencing after December 31, 2012, for a Phase II Utility and 
 after December 31, 2013, for a Phase I Utility, more than 70 basis points below 
 a fair combined rate of return on its generation and distribution services, as 
 determined in subdivision 2, without regard to any return on common equity or 
 other matters determined with respect to facilities described in subdivision 6, 
 the Commission shall order increases to the utilitys rates necessary to 
 provide the opportunity to fully recover the costs of providing the utilitys 
 services and to earn not less than such fair combined rate of return, using the 
 most recently ended 12-month test period as the basis for determining the 
 amount of the rate increase necessary. However, in the first triennial review 
 proceeding conducted after January 1, 2021, for a Phase II Utility, the 
 Commission may not order a rate increase, and in all triennial reviews of a 
 Phase I or Phase II utility, the Commission may not order such rate increase 
 unless it finds that the resulting rates are necessary to provide the utility 
 with the opportunity to fully recover its costs of providing its services and to 
 earn not less than a fair combined rate of return on both its generation and 
 distribution services, as determined in subdivision 2, without regard to any 
 return on common equity or other matters determined with respect to facilities 
 described in subdivision 6, using the most recently ended 12-month test period 
 as the basis for determining the permissibility of any rate increase under the 
 standards of this sentence, and the amount thereof; and provided that, solely 
 in connection with making its determination concerning the necessity for such a 
 rate increase or the amount thereof, the Commission shall, in any triennial 
 review proceeding conducted prior to July 1, 2028, exclude from this most 
 recently ended 12-month test period any remaining investment levels associated 
 with a prior customer credit reinvestment offset pursuant to subdivision d.
 
 
b. The utility has, during the test period or test periods 
 under review, considered as a whole, earned more than 50 basis points above a 
 fair combined rate of return on its generation and distribution services or, 
 for any test period commencing after December 31, 2012, for a Phase II Utility 
 and after December 31, 2013, for a Phase I Utility, more than 70 basis points 
 above a fair combined rate of return on its generation and distribution 
 services, as determined in subdivision 2, without regard to any return on 
 common equity or other matters determined with respect to facilities described 
 in subdivision 6, the Commission shall, subject to the provisions of 
 subdivisions 8 d and 9, direct that 60 percent of the amount of such earnings 
 that were more than 50 basis points, or, for any test period commencing after 
 December 31, 2012, for a Phase II Utility and after December 31, 2013, for a 
 Phase I Utility, that 70 percent of the amount of such earnings that were more 
 than 70 basis points, above such fair combined rate of return for the test 
 period or periods under review, considered as a whole, shall be credited to 
 customers bills. Any such credits shall be amortized over a period of six to 
 12 months, as determined at the discretion of the Commission, following the 
 effective date of the Commissions order, and shall be allocated among customer 
 classes such that the relationship between the specific customer class rates of 
 return to the overall target rate of return will have the same relationship as 
 the last approved allocation of revenues used to design base rates; or
 
 
c. In any triennial review proceeding conducted after January 
 1, 2020, for a Phase I Utility or after January 1, 2021, for a Phase II Utility 
 in which the utility has, during the test period or test periods under review, 
 considered as a whole, earned more than 50 basis points above a fair combined 
 rate of return on its generation and distribution services or, for any test 
 period commencing after December 31, 2012, for a Phase II Utility and after 
 December 31, 2013, for a Phase I Utility, more than 70 basis points above a 
 fair combined rate of return on its generation and distribution services, as 
 determined in subdivision 2, without regard to any return on common equity or 
 other matter determined with respect to facilities described in subdivision 6, 
 and the combined aggregate level of capital investment that the Commission has 
 approved other than those capital investments that the Commission has approved 
 for recovery pursuant to a rate adjustment clause pursuant to subdivision 6 
 made by the utility during the test periods under review in that triennial 
 review proceeding in new utility-owned generation facilities utilizing energy 
 derived from sunlight, or from wind, and in electric distribution grid 
 transformation projects, as determined pursuant to subdivision 8 d, does not 
 equal or exceed 100 percent of the earnings that are more than 70 basis points 
 above the utilitys fair combined rate of return on its generation and 
 distribution services for the combined test periods under review in that 
 triennial review proceeding, the Commission shall, subject to the provisions of 
 subdivision 9 and in addition to the actions authorized in subdivision b, also 
 order reductions to the utilitys rates it finds appropriate. However, in the 
 first triennial review proceeding conducted after January 1, 2021, for a Phase 
 II Utility, any reduction to the utilitys rates ordered by the Commission 
 pursuant to this subdivision shall not exceed $50 million in annual revenues, 
 with any reduction allocated to the utilitys rates for generation services, 
 and in each triennial review of a Phase I or Phase II Utility, the Commission 
 may not order such rate reduction unless it finds that the resulting rates will 
 provide the utility with the opportunity to fully recover its costs of 
 providing its services and to earn not less than a fair combined rate of return 
 on its generation and distribution services, as determined in subdivision 2, 
 without regard to any return on common equity or other matters determined with 
 respect to facilities described in subdivision 6, using the most recently ended 
 12-month test period as the basis for determining the permissibility of any 
 rate reduction under the standards of this sentence, and the amount thereof; 
 and
 
 
d. (Expires July 1, 2028) In any triennial review proceeding 
 conducted after December 31, 2017, upon the request of the utility, the 
 Commission shall determine, prior to directing that 70 percent of earnings that 
 are more than 70 basis points above the utilitys fair combined rate of return 
 on its generation and distribution services for the test period or periods 
 under review be credited to customer bills pursuant to subdivision 8 b, the 
 aggregate level of prior capital investment that the Commission has approved 
 other than those capital investments that the Commission has approved for 
 recovery pursuant to a rate adjustment clause pursuant to subdivision 6 made by 
 the utility during the test period or periods under review in both (i) new 
 utility-owned generation facilities utilizing energy derived from sunlight, or 
 from onshore or offshore wind, and (ii) electric distribution grid 
 transformation projects, as determined by the utilitys plant in service and 
 construction work in progress balances related to such investments as recorded 
 per books by the utility for financial reporting purposes as of the end of the 
 most recent test period under review. Any such combined capital investment 
 amounts shall offset any customer bill credit amounts, on a dollar for dollar 
 basis, up to the aggregate level of invested or committed capital under clauses 
 (i) and (ii). The aggregate level of qualifying invested or committed capital under 
 clauses (i) and (ii) is referred to in this subdivision as the customer credit 
 reinvestment offset, which offsets the customer bill credit amount that the 
 utility has invested or will invest in new solar or wind generation facilities 
 or electric distribution grid transformation projects for the benefit of 
 customers, in amounts up to 100 percent of earnings that are more than 70 basis 
 points above the utilitys fair rate of return on its generation and 
 distribution services, and thereby reduce or eliminate otherwise incremental 
 rate adjustment clause charges and increases to customer bills, which is deemed 
 to be in the public interest. If 100 percent of the amount of earnings that are 
 more than 70 basis points above the utilitys fair combined rate of return on 
 its generation and distribution services, as determined in subdivision 2, 
 exceeds the aggregate level of invested capital in new utility-owned generation 
 facilities utilizing energy derived from sunlight, or from wind, and electric 
 distribution grid transformation projects, as provided in clauses (i) and (ii), 
 during the test period or periods under review, then 70 percent of the amount 
 of such excess shall be credited to customer bills as provided in subdivision 8 
 b in connection with the triennial review proceeding. The portion of any costs 
 associated with new utility-owned generation facilities utilizing energy 
 derived from sunlight, or from wind, or electric distribution grid 
 transformation projects that is the subject of any customer credit reinvestment 
 offset pursuant to this subdivision shall not thereafter be recovered through 
 the utilitys rates for generation and distribution services over the service 
 life of such facilities and shall not thereafter be included in the utilitys 
 costs, revenues, and investments in future triennial review proceedings 
 conducted pursuant to subdivision 2 and shall not be the subject of a rate 
 adjustment clause petition pursuant to subdivision 6. The portion of any costs 
 associated with new utility-owned generation facilities utilizing energy 
 derived from sunlight, or from wind, or electric distribution grid 
 transformation projects that is not the subject of any customer credit 
 reinvestment offset pursuant to this subdivision may be recovered through the 
 utilitys rates for generation and distribution services over the service life 
 of such facilities and shall be included in the utilitys costs, revenues, and 
 investments in future triennial review proceedings conducted pursuant to 
 subdivision 2 until such costs are fully recovered, and if such costs are 
 recovered through the utilitys rates for generation and distribution services, 
 they shall not be the subject of a rate adjustment clause petition pursuant to 
 subdivision 6. Only the portion of such costs of new utility-owned generation 
 facilities utilizing energy derived from sunlight, or from wind, or electric 
 distribution grid transformation projects that has not been included in any 
 customer credit reinvestment offset pursuant to this subdivision, and not 
 otherwise recovered through the utilitys rates for generation and distribution 
 services, may be the subject of a rate adjustment clause petition by the 
 utility pursuant to subdivision 6.
 
 
The Commissions final order regarding such triennial review 
 shall be entered not more than eight months after the date of filing, and any 
 revisions in rates or credits so ordered shall take effect not more than 60 
 days after the date of the order. The fair combined rate of return on common 
 equity determined pursuant to subdivision 2 in such triennial review shall 
 apply, for purposes of reviewing the utilitys earnings on its rates for 
 generation and distribution services, to the entire three successive 12-month 
 test periods ending December 31 immediately preceding the year of the utilitys 
 subsequent triennial review filing under subdivision 3 and shall apply to 
 applicable rate adjustment clauses under subdivisions 5 and 6 prospectively 
 from the date the Commissions final order in the triennial review proceeding, 
 utilizing rate adjustment clause true-up protocols as the Commission in its 
 discretion may determine.
 
 
9. If, as a result of a triennial review required under this 
 subsection and conducted with respect to any test period or periods under 
 review ending later than December 31, 2010 (or, if the Commission has elected 
 to stagger its biennial reviews of utilities as provided in subdivision 1, 
 under review ending later than December 31, 2010, for a Phase I Utility, or 
 December 31, 2011, for a Phase II Utility), the Commission finds, with respect 
 to such test period or periods considered as a whole, that (i) any utility has, 
 during the test period or periods under review, considered as a whole, earned 
 more than 50 basis points above a fair combined rate of return on its 
 generation and distribution services or, for any test period commencing after 
 December 31, 2012, for a Phase II Utility and after December 31, 2013, for a 
 Phase I Utility, more than 70 basis points above a fair combined rate of return 
 on its generation and distribution services, as determined in subdivision 2, 
 without regard to any return on common equity or other matters determined with 
 respect to facilities described in subdivision 6, and (ii) the total aggregate 
 regulated rates of such utility at the end of the most recently ended 12-month 
 test period exceeded the annual increases in the United States Average Consumer 
 Price Index for all items, all urban consumers (CPI-U), as published by the 
 Bureau of Labor Statistics of the United States Department of Labor, compounded 
 annually, when compared to the total aggregate regulated rates of such utility 
 as determined pursuant to the review conducted for the base period, the 
 Commission shall, unless it finds that such action is not in the public 
 interest or that the provisions of subdivisions 8 b and c are more consistent 
 with the public interest, direct that any or all earnings for such test period 
 or periods under review, considered as a whole that were more than 50 basis 
 points, or, for any test period commencing after December 31, 2012, for a Phase 
 II Utility and after December 31, 2013, for a Phase I Utility, more than 70 
 basis points, above such fair combined rate of return shall be credited to 
 customers bills, in lieu of the provisions of subdivisions 8 b and c, provided 
 that no credits shall be provided pursuant to this subdivision in connection 
 with any triennial review unless such bill credits would be payable pursuant to 
 the provisions of subdivision 8 d, and any credits under this subdivision shall 
 be calculated net of any customer credit reinvestment offset amounts under 
 subdivision 8 d. Any such credits shall be amortized and allocated among 
 customer classes in the manner provided by subdivision 8 b. For purposes of 
 this subdivision:
 
 
"Base period" means (i) the test period ending 
 December 31, 2010 (or, if the Commission has elected to stagger its biennial 
 reviews of utilities as provided in subdivision 1, the test period ending 
 December 31, 2010, for a Phase I Utility, or December 31, 2011, for a Phase II 
 Utility), or (ii) the most recent test period with respect to which credits 
 have been applied to customers bills under the provisions of this subdivision, 
 whichever is later.
 
 
"Total aggregate regulated rates" shall include: (i) 
 fuel tariffs approved pursuant to � 56-249.6, except for any increases in fuel 
 tariffs deferred by the Commission for recovery in periods after December 31, 
 2010, pursuant to the provisions of clause (ii) of subsection C of � 56-249.6; 
 (ii) rate adjustment clauses implemented pursuant to subdivision 4 or 5; (iii) 
 revisions to the utilitys rates pursuant to subdivision 8 a; (iv) revisions to 
 the utilitys rates pursuant to the Commissions rules governing utility rate 
 increase applications, as permitted by subsection B, occurring after July 1, 
 2009; and (v) base rates in effect as of July 1, 2009.
 
 
10. For purposes of this section, the Commission shall 
 regulate the rates, terms and conditions of any utility subject to this section 
 on a stand-alone basis utilizing the actual end-of-test period capital 
 structure and cost of capital of such utility, excluding any debt associated 
 with securitized bonds that are the obligation of non-Virginia jurisdictional 
 customers, unless the Commission finds that the debt to equity ratio of such 
 capital structure is unreasonable for such utility, in which case the 
 Commission may utilize a debt to equity ratio that it finds to be reasonable 
 for such utility in determining any rate adjustment pursuant to subdivisions 8 
 a and c, and without regard to the cost of capital, capital structure, 
 revenues, expenses or investments of any other entity with which such utility 
 may be affiliated. In particular, and without limitation, the Commission shall 
 determine the federal and state income tax costs for any such utility that is 
 part of a publicly traded, consolidated group as follows: (i) such utilitys 
 apportioned state income tax costs shall be calculated according to the 
 applicable statutory rate, as if the utility had not filed a consolidated 
 return with its affiliates, and (ii) such utilitys federal income tax costs 
 shall be calculated according to the applicable federal income tax rate and 
 shall exclude any consolidated tax liability or benefit adjustments originating 
 from any taxable income or loss of its affiliates.
 
 
B. Nothing in this section shall preclude an investor-owned 
 incumbent electric utility from applying for an increase in rates pursuant to � 
 56-245 or the Commissions rules governing utility rate increase applications; 
 however, in any such filing, a fair rate of return on common equity shall be 
 determined pursuant to subdivision A 2. Nothing in this section shall preclude 
 such utilitys recovery of fuel and purchased power costs as provided in � 
 56-249.6.
 
 
C. Except as otherwise provided in this section, the Commission 
 shall exercise authority over the rates, terms and conditions of investor-owned 
 incumbent electric utilities for the provision of generation, transmission and 
 distribution services to retail customers in the Commonwealth pursuant to the 
 provisions of Chapter 10 (� 56-232 et seq.), including specifically � 56-235.2.
 
 
D. The Commission may determine, during any proceeding 
 authorized or required by this section, the reasonableness or prudence of any 
 cost incurred or projected to be incurred, by a utility in connection with the 
 subject of the proceeding. A determination of the Commission regarding the 
 reasonableness or prudence of any such cost shall be consistent with the 
 Commissions authority to determine the reasonableness or prudence of costs in proceedings 
 pursuant to the provisions of Chapter 10 (� 56-232 et seq.). In determining the 
 reasonableness or prudence of a utility providing energy and capacity to its 
 customers from renewable energy resources, the Commission shall consider the 
 extent to which such renewable energy resources, whether utility-owned or by 
 contract, further the objectives of the Commonwealth Energy Policy set forth in 
 �� 67-101 and 67-102, and shall also consider whether the costs of such 
 resources is likely to result in unreasonable increases in rates paid by 
 customers.
 
 
E. The Commission shall promulgate such rules and regulations 
 as may be necessary to implement the provisions of this section.
 
 
� 56-585.2. Sales of electricity to comply with clean energy 
 standard program. 
 
 
A. As used in this section:
 
 
"Qualified 
 investment" means an expense incurred in the Commonwealth by a 
 participating utility in conducting, either by itself or in partnership with 
 institutions of higher education in the Commonwealth or with industrial or 
 commercial customers that have established renewable energy research and 
 development programs in the Commonwealth, research and development activities 
 related to renewable or alternative energy sources, which expense (i) is 
 designed to enhance the participating utilitys understanding of emerging 
 energy technologies and their potential impact on and value to the utilitys 
 system and customers within the Commonwealth; (ii) promotes economic 
 development within the Commonwealth; (iii) supplements customer-driven alternative 
 energy or energy efficiency initiatives; (iv) supplements alternative energy 
 and energy efficiency initiatives at state or local governmental facilities in 
 the Commonwealth; or (v) is designed to mitigate the environmental impacts of 
 renewable energy projects.
 
 
"Renewable energy" 
 shall have the same meaning ascribed to it in � 56-576, provided such renewable 
 energy is (i) generated in the Commonwealth or in the interconnection region of 
 the regional transmission entity of which the participating utility is a 
 member, as it may change from time to time, and purchased by a participating 
 utility under a power purchase agreement; provided, however, that if such 
 agreement was executed on or after July 1, 2013, the agreement shall expressly 
 transfer ownership of renewable attributes, in addition to ownership of the 
 energy, to the participating utility; (ii) generated by a public utility 
 providing electric service in the Commonwealth from a facility in which the 
 public utility owns at least a 49 percent interest and that is located in the 
 Commonwealth, in the interconnection region of the regional transmission entity 
 of which the participating utility is a member, or in a control area adjacent 
 to such interconnection region; or (iii) represented by renewable energy 
 certificates. "Renewable energy" shall not include electricity 
 generated from pumped storage, but shall include run-of-river generation from a 
 combined pumped-storage and run-of-river facility.
 
 
"Clean energy" 
 means electricity generated by a clean energy resource.
 
 
"Renewable Clean energy 
 certificate" means either (i) 
 a certificate issued by an affiliate of the regional transmission entity of 
 which the participating utility is a member, as it may change from time to 
 time, or any successor to such affiliate, and held or acquired by such utility, 
 that validates the generation of renewable 
 energy by eligible sources a clean energy resource in the 
 interconnection region of the regional transmission entity or (ii) a 
 certificate issued by the Commission pursuant to subsection J and held or 
 acquired by a participating utility, that validates a qualified investment made 
 by the participating utility.
 
 
"Clean energy 
 resource" means electricity produced by any 
 technology used to generate electricity without 
 emitting carbon dioxide into the atmosphere. "Clean 
 energy resources" include (i) electric 
 generation facilities that are powered by nuclear, solar, wind, falling water, 
 wave motion, tides, or geothermal power; (ii) a natural gas-fired 
 generation facility with 80 percent carbon capture; or (iii) a coal-fired 
 generation facility with 90 percent carbon capture.
 
 
"Total electric energy 
 sold in the base year" means total electric energy sold to Virginia 
 jurisdictional retail customers by a participating utility in calendar year 
 2007, excluding an amount equivalent to the average of the annual percentages 
 of the electric energy that was supplied to such customers from nuclear 
 generating plants for the calendar years 2004 through 2006.
 
 
"Utility" means any 
 investor-owned utility, including 
 an investor-owned electric utility described in 
 subsection G of � 56-580, or cooperative electric 
 utility.
 
 
B. Any investor-owned incumbent Each electric utility may apply to the Commission for approval 
 to participate in a renewable shall 
 comply with the clean energy portfolio 
 standard program, as defined established in this section. The Commission shall approve such application if 
 the applicant demonstrates that it has a reasonable expectation of achieving 12 
 percent of its base year electric energy sales from renewable energy sources 
 during calendar year 2022, and 15 percent of its base year electric energy 
 sales from renewable energy sources during calendar year 2025, as provided in 
 subsection D.
 
 
C. It is in the public interest for utilities that seek to have a renewable energy portfolio standard 
 program to achieve the goals requirements set forth in 
 subsection D, such goals requirements being referred to 
 herein as "RPS CES Goals." A utility shall receive double credit toward 
 meeting the renewable energy portfolio standard for energy derived from 
 sunlight, from onshore wind, or from facilities in the Commonwealth fueled 
 primarily by animal waste, and triple credit toward meeting the renewable 
 energy portfolio standard for energy derived from offshore wind.
 
 
D. Regarding any renewable The clean energy portfolio standard program, requires 
 the total electric energy sold by a utility to meet the RPS following CES 
 Goals shall be composed of the following amounts of 
 electric energy or renewable thermal energy equivalent from renewable energy 
 sources, as adjusted for any sales volumes lost through operation of the 
 customer choice provisions of subdivision A 3 or A 4 of � 56-577 at a minimum:
 
 
RPS Goal I: In calendar year 
 2010, 4 percent of total electric energy sold in the base year.
 
 
RPS Goal II: For calendar 
 years 2011 through 2015, inclusive, an average of 4 percent of total electric 
 energy sold in the base year, and in calendar year 2016, 7 percent of total 
 electric energy sold in the base year.
 
 
RPS Goal III: For calendar 
 years 2017 through 2021, inclusive, an average of 7 percent of total electric 
 energy sold in the base year, and in calendar year 2022, 12 percent of total 
 electric energy sold in the base year.
 
 
RPS Goal IV: For calendar 
 years 2023 and 2024, inclusive, an average of 12 percent of total electric 
 energy sold in the base year, and in calendar year 2025, 15 percent of total 
 electric energy sold in the base year.
 
 
A utility may not apply 
 renewable energy certificates issued pursuant to subsection J to meet more than 
 20 percent of the sales requirement for the RPS Goal in any year.
 
 
A utility may apply renewable 
 energy sales achieved or renewable energy certificates acquired during the 
 periods covered by any such RPS Goal that are in excess of the sales 
 requirement for that RPS Goal to the sales requirements for any future RPS 
 Goals in the five calendar years after the renewable energy was generated or 
 the renewable energy certificates were created, except that a utility shall be 
 able to apply renewable energy certificates acquired by the utility prior to 
 January 1, 2014.
 
 
1. In 2030, 30 percent 
 of the electric energy sold by a utility to Virginia 
 customers shall be clean energy; 
 
 
2. In 2031, 33 percent of 
 the electric energy sold by a utility to Virginia customers shall be clean 
 energy;
 
 
3. In 2032, 36 percent of 
 the electric energy sold by a utility to Virginia customers shall be clean 
 energy;
 
 
4. In 2033, 39 percent of 
 the electric energy sold by a utility to Virginia customers shall be clean 
 energy;
 
 
5. In 2034, 42 percent of 
 the electric energy sold by a utility to Virginia customers shall be clean 
 energy;
 
 
6. In 2035, 45 percent of 
 the electric energy sold by a utility to Virginia customers shall be clean 
 energy;
 
 
7. In 2036, 48 percent of 
 the electric energy sold by a utility to Virginia customers shall be clean 
 energy;
 
 
8. In 2037, 51 percent of 
 the electric energy sold by a utility to Virginia customers shall be clean 
 energy;
 
 
9. In 2038, 54 percent of 
 the electric energy sold by a utility to Virginia customers shall be clean 
 energy;
 
 
10. In 2039, 57 percent of 
 the electric energy sold by a utility to Virginia customers shall be clean 
 energy;
 
 
11. In 2040, 60 percent of 
 the electric energy sold by a utility to Virginia customers shall be clean 
 energy;
 
 
12. In 2041, 64 percent of 
 the electric energy sold by a utility to Virginia customers shall be clean 
 energy;
 
 
13. In 2042, 68 percent of 
 the electric energy sold by a utility to Virginia customers shall be clean 
 energy;
 
 
14. In 2043, 72 percent of 
 the electric energy sold by a utility to Virginia customers shall be clean 
 energy;
 
 
15. In 2044, 76 percent of 
 the electric energy sold by a utility to Virginia customers shall be clean 
 energy;
 
 
16. In 2045, 80 percent of 
 the electric energy sold by a utility to Virginia customers shall be clean 
 energy;
 
 
17. In 2046, 84 percent of 
 the electric energy sold by a utility to Virginia customers shall be clean 
 energy;
 
 
18. In 2047, 88 percent of 
 the electric energy sold by a utility to Virginia customers shall be clean 
 energy;
 
 
19. In 2048, 92 percent of 
 the electric energy sold by a utility to Virginia customers shall be clean 
 energy;
 
 
20. In 2049, 96 percent of 
 the electric energy sold by a utility to Virginia customers shall be clean 
 energy; and
 
 
21. In 2050 and 
 thereafter, 100 percent 
 of the electric energy sold by a utility to Virginia customers shall be clean 
 energy.
 
 
E. A utility participating in such 
 program shall have the right to recover all incremental 
 costs incurred for the purpose of such participation 
 in such efforts to 
 comply with the CES program, as accrued against income, if (i) the utility is subject to � 56-585.1 
 through rate adjustment clauses as provided in subdivisions A 5 and A 6 of � 56-585.1, including, but not limited to, 
 administrative costs, ancillary costs, capacity costs, costs of clean energy represented by certificates described in 
 subsection A, and, in the case of construction of renewable clean 
 energy generation 
 facilities, allowance for funds used during construction until such time as an 
 enhanced rate of return, as determined pursuant to subdivision A 6 of � 
 56-585.1, on construction work in progress is included in rates, projected 
 construction work in progress, planning, development and construction costs, 
 life-cycle costs, and costs of infrastructure associated therewith, plus an 
 enhanced rate of return, as determined pursuant to subdivision A 6 of � 
 56-585.1, or (ii) through a rate case 
 under Chapter 10 (� 56-232 et seq.) if the utility is not 
 subject to � 56-585.1. This 
 subsection shall not apply to qualified investments as provided in subsection 
 K. All incremental costs of the RPS CES program shall be allocated 
 to and recovered from the utilitys customer classes based on the demand 
 created by the class and within the class based on energy used by the 
 individual customer in the class, except that the incremental 
 costs of the RPS program shall not be allocated to or recovered from customers 
 that are served within the large industrial rate classes of the participating 
 utilities and that are served at primary or transmission voltage. Notwithstanding anything in this title to the 
 contrary, however, a utilitys 
 costs incurred in efforts to comply 
 with the CES program shall not be recovered in any 
 year if and to the extent that such recovery would 
 result in an increase to the rates charged to the 
 utilitys customers for a year by an average of 10 percent 
 or more. 
 
 
F. A utility participating in such 
 program shall apply towards 
 meeting its RPS CES 
 Goals any renewable clean 
 energy from existing renewable clean energy sources owned by 
 the participating utility or 
 purchased as allowed by contract at no additional cost to customers to the 
 extent feasible. A utility participating in such 
 program shall not apply towards 
 meeting its RPS CES 
 Goals renewable clean 
 energy certificates attributable to any renewable clean 
 energy generated at a renewable clean energy 
 generation source in operation as of July 1, 2007, that is operated by a person 
 that is served within a utilitys large industrial rate class and that is 
 served at primary or transmission voltage, except 
 for those persons providing renewable thermal energy equivalents to the utility. 
 A participating utility shall be 
 required to fulfill any remaining deficit needed to fulfill its RPS CES 
 Goals from new renewable clean 
 energy supplies resources 
 at reasonable cost and in a prudent manner to be determined by the Commission at the time of approval of any application made 
 pursuant to subsection B. A 
 participating utility may sell renewable clean energy certificates 
 produced at its own generation clean energy facilities 
 located in the Commonwealth or, if located outside the Commonwealth, owned by 
 such utility and in operation as of January 1, 2010, or renewable clean 
 energy certificates acquired as part of a purchase power agreement, to another 
 entity and purchase lower cost renewable clean 
 energy certificates and the net difference in price between the renewable clean 
 energy certificates shall be credited to customers. Utilities 
 participating in such program shall collectively, either through the 
 installation of new generating facilities, through retrofit of existing 
 facilities or through purchases of electricity from new facilities located in 
 Virginia, use or cause to be used no more than a total of 1.5 million tons per 
 year of green wood chips, bark, sawdust, a tree or any portion of a tree which 
 is used or can be used for lumber and pulp manufacturing by facilities located 
 in Virginia, towards meeting RPS goals, excluding such fuel used at electric 
 generating facilities using wood as fuel prior to January 1, 2007. A utility 
 with an approved application shall be allocated a portion of the 1.5 million 
 tons per year in proportion to its share of the total electric energy sold in 
 the base year, as defined in subsection A, for all utilities participating in 
 the RPS program. A utility may use in meeting RPS goals, without limitation, 
 the following sustainable biomass and biomass based waste to energy resources: 
 mill residue, except wood chips, sawdust and bark; pre-commercial soft wood 
 thinning; slash; logging and construction debris; brush; yard waste; shipping crates; 
 dunnage; non-merchantable waste paper; landscape or right-of-way tree 
 trimmings; agricultural and vineyard materials; grain; legumes; sugar; and gas 
 produced from the anaerobic decomposition of animal waste.
 
 
G. The Commission shall promulgate adopt such rules and 
 regulations as may be necessary to implement the provisions of this section 
 including a requirement that participants utilities verify whether the RPS CES 
 goals are met in accordance with this section.
 
 
H. Each investor-owned incumbent 
 electric utility shall report to the Commission annually by 
 November 1 identifying:
 
 
1. The utilitys efforts, if any, to meet the RPS CES 
 Goals, specifically identifying:
 
 
a. A list of all states where the purchased or owned renewable clean 
 energy was generated, specifying the number of megawatt hours or renewable clean 
 energy certificates originating from each state;
 
 
b. A list of the decades in which the purchased or owned renewable clean 
 energy generating units were placed in service, specifying the number of megawatt 
 hours or renewable clean 
 energy certificates originating from those units; and
 
 
c. A list of fuel types used to generate the purchased or 
 owned renewable clean 
 energy, specifying the number of megawatt hours or renewable clean 
 energy certificates originating from each fuel type;
 
 
2. The utilitys overall generation of renewable clean 
 energy; and
 
 
3. Advances in renewable clean 
 generation technology that affect activities described in subdivisions 1 and 2.
 
 
I. The Commission shall post on its website the reports 
 submitted by each investor-owned incumbent electric utility pursuant to 
 subsection H.
 
 
J. The Commission shall issue 
 to a participating utility a number of renewable energy certificates for 
 qualified investments, upon request by a participating utility, if it finds 
 that an expense satisfies the conditions set forth in this section for a 
 qualified investment, as follows: 
 
 
1. By March 31 of each year, 
 the participating utility shall provide an analysis, as reasonably determined 
 by a qualified independent broker, of the average for the preceding year of the 
 publicly available prices for Tier 1 renewable energy certificates and Tier 2 
 renewable energy certificates, validating the generation of renewable energy by 
 eligible sources, that were issued in the interconnection region of the 
 regional transmission entity of which the participating utility is a member;
 
 
2. In the same annual 
 analysis provided to the Commission, the participating utility shall divide the 
 amount of the participating utilitys qualified investments in the applicable 
 period by the average price determined pursuant to subdivision 1;
 
 
3. The number of renewable 
 energy certificates to be issued to the participating utility shall equal the 
 product obtained pursuant to subdivision 2; and
 
 
4. The Commission shall 
 review and validate the analysis provided by the participating utility within 
 90 days of submittal of its analysis to the Commission. If no corrections are 
 made by the Commission, then the analysis shall be deemed correct and the 
 renewable energy certificates shall be deemed issued to the participating 
 utility.
 
 
Each renewable energy 
 certificate issued to a participating utility pursuant to this subsection shall 
 represent the equivalent of one megawatt hour of renewable energy sales 
 achieved when applied to an RPS Goal Any 
 utility may satisfy the requirements of this section by acquiring CES 
 certificates through an interstate market-based credit trading program to which 
 the Commonwealth is a participant. 
 
 
K. Qualified 
 investments shall constitute reasonable and prudent operating expenses of a 
 participating utility. Notwithstanding subsection E, a participating utility 
 shall not be authorized to recover the costs associated with qualified 
 investments through rate adjustment clauses as provided in subdivisions A 5 and 
 A 6 of � 56-585.1. In any proceeding conducted pursuant to � 56-585.1 or other 
 provision of this title in which a participating utility seeks recovery of its 
 qualified investments as an operating expense, the participating utility shall 
 not be authorized to earn a return on its qualified investments A utility that fails to 
 achieve a CES Goal shall pay into the Renewable 
 Electricity Production Grant Fund established pursuant to � 67-902 a compliance 
 payment. The Commission shall determine the market 
 price for clean energy certificates each year. A 
 utilitys compliance payment shall be the product 
 obtained by multiplying the market price for clean energy certificates by the 
 number of such certificates the utility would have needed to 
 purchase that year to meet the applicable CES Goal.
 
 
L. A participating utility 
 shall not be eligible for a research and development tax credit pursuant to � 
 58.1-439.12:08 or 58.1-439.12:11 with regard to any expense incurred or 
 investment made by the participating utility that constitutes a qualified 
 investment pursuant to this section. 
 
 
� 56-594. Net energy metering provisions.
 
 
A. The Commission shall establish by regulation a program that 
 affords eligible customer-generators the opportunity to participate in net 
 energy metering, and a program, to begin no later than July 1, 2014, for 
 customers of investor-owned utilities and to begin no later than July 1, 2015, 
 and to end July 1, 2019, for customers of electric cooperatives as provided in 
 subsection G, to afford eligible agricultural customer-generators the 
 opportunity to participate in net energy metering. The regulations may include, 
 but need not be limited to, requirements for (i) retail sellers; (ii) owners or 
 operators of distribution or transmission facilities; (iii) providers of 
 default service; (iv) eligible customer-generators; (v) eligible agricultural 
 customer-generators; or (vi) any combination of the foregoing, as the 
 Commission determines will facilitate the provision of net energy metering, 
 provided that the Commission determines that such requirements do not adversely 
 affect the public interest. On and after July 1, 2017, small agricultural 
 generators or eligible agricultural customer-generators may elect to 
 interconnect pursuant to the provisions of this section or as small 
 agricultural generators pursuant to � 56-594.2, but not both. Existing eligible 
 agricultural customer-generators may elect to become small agricultural 
 generators, but may not revert to being eligible agricultural 
 customer-generators after such election. On and after July 1, 2019, 
 interconnection of eligible agricultural customer-generators shall cease for 
 electric cooperatives only, and such facilities shall interconnect solely as 
 small agricultural generators. For electric cooperatives, eligible agricultural 
 customer-generators whose renewable energy generating facilities were 
 interconnected before July 1, 2019, may continue to participate in net energy 
 metering pursuant to this section for a period not to exceed 25 years from the 
 date of their renewable energy generating facilitys original interconnection.
 
 
B. For the purpose of this section:
 
 
"Eligible agricultural customer-generator" means a 
 customer that operates a renewable energy generating facility as part of an 
 agricultural business, which generating facility (i) uses as its sole energy 
 source solar power, wind power, or aerobic or anaerobic digester gas, (ii) does 
 not have an aggregate generation capacity of more than 500 kilowatts, (iii) is 
 located on land owned or controlled by the agricultural business, (iv) is 
 connected to the customers wiring on the customers side of its 
 interconnection with the distributor; (v) is interconnected and operated in 
 parallel with an electric companys transmission and distribution facilities, 
 and (vi) is used primarily to provide energy to metered accounts of the 
 agricultural business. An eligible agricultural customer-generator may be 
 served by multiple meters that are located at separate but contiguous sites, 
 such that the eligible agricultural customer-generator may aggregate in a 
 single account the electricity consumption and generation measured by the 
 meters, provided that the same utility serves all such meters. The aggregated 
 load shall be served under the appropriate tariff.
 
 
"Eligible customer-generator" means a customer that 
 owns and operates, or contracts with other persons to own, operate, or both, an 
 electrical generating facility that (i) has a capacity of not more than 20 
 kilowatts for residential customers and not more than one megawatt for 
 nonresidential customers on an electrical generating facility placed in service 
 after July 1, 2015; (ii) uses as its total source of fuel renewable energy, as 
 defined in � 56-576; (iii) is located on the customers premises and is 
 connected to the customers wiring on the customers side of its 
 interconnection with the distributor; (iv) is interconnected and operated in 
 parallel with an electric companys transmission and distribution facilities; 
 and (v) is intended primarily to offset all or part of the customers own 
 electricity requirements. In addition to the electrical generating facility 
 size limitations in clause (i), the capacity of any generating facility installed 
 under this section after July 1, 2015, shall not exceed the expected annual 
 energy consumption based on the previous 12 months of billing history or an 
 annualized calculation of billing history if 12 months of billing history is 
 not available.
 
 
"Net energy metering" means measuring the 
 difference, over the net metering period, between (i) electricity supplied to 
 an eligible customer-generator or eligible agricultural customer-generator from 
 the electric grid and (ii) the electricity generated and fed back to the 
 electric grid by the eligible customer-generator or eligible agricultural 
 customer-generator.
 
 
"Net metering period" means the 12-month period 
 following the date of final interconnection of the eligible 
 customer-generators or eligible agricultural customer-generators system with 
 an electric service provider, and each 12-month period thereafter.
 
 
"Small agricultural generator" has the same meaning 
 that is ascribed to that term in � 56-594.2.
 
 
C. The Commissions regulations shall ensure that (i) the 
 metering equipment installed for net metering shall be capable of measuring the 
 flow of electricity in two directions and (ii) any eligible customer-generator 
 seeking to participate in net energy metering shall notify its supplier and 
 receive approval to interconnect prior to installation of an electrical 
 generating facility. The electric distribution company shall have 30 days from 
 the date of notification for residential facilities, and 60 days from the date 
 of notification for nonresidential facilities, to determine whether the 
 interconnection requirements have been met. Such regulations shall allocate 
 fairly the cost of such equipment and any necessary interconnection. An 
 eligible customer-generators electrical generating system, and each electrical 
 generating system of an eligible agricultural customer-generator, shall meet 
 all applicable safety and performance standards established by the National 
 Electrical Code, the Institute of Electrical and Electronics Engineers, and 
 accredited testing laboratories such as Underwriters Laboratories. Beyond the 
 requirements set forth in this section and to ensure public safety, power 
 quality, and reliability of the suppliers electric distribution system, an 
 eligible customer-generator or eligible agricultural customer-generator whose 
 electrical generating system meets those standards and rules shall bear all 
 reasonable costs of equipment required for the interconnection to the 
 suppliers electric distribution system, including costs, if any, to (a) 
 install additional controls, (b) perform or pay for additional tests, and (c) 
 purchase additional liability insurance.
 
 
D. The Commission shall establish minimum requirements for 
 contracts to be entered into by the parties to net metering arrangements. Such 
 requirements shall protect the eligible customer-generator or eligible 
 agricultural customer-generator against discrimination by virtue of its status 
 as an eligible customer-generator or eligible agricultural customer-generator, 
 and permit customers that are served on time-of-use tariffs that have 
 electricity supply demand charges contained within the electricity supply 
 portion of the time-of-use tariffs to participate as an eligible 
 customer-generator or eligible agricultural customer-generator. Notwithstanding 
 the cost allocation provisions of subsection C, eligible customer-generators or 
 eligible agricultural customer-generators served on demand charge-based 
 time-of-use tariffs shall bear the incremental metering costs required to net 
 meter such customers.
 
 
E. If electricity generated by an eligible customer-generator 
 or eligible agricultural customer-generator over the net metering period 
 exceeds the electricity consumed by the eligible customer-generator or eligible 
 agricultural customer-generator, the customer-generator or eligible 
 agricultural customer-generator shall be compensated for the excess electricity 
 if the entity contracting to receive such electric energy and the eligible 
 customer-generator or eligible agricultural customer-generator enter into a 
 power purchase agreement for such excess electricity. Upon the written request 
 of the eligible customer-generator or eligible agricultural customer-generator, 
 the supplier that serves the eligible customer-generator or eligible 
 agricultural customer-generator shall enter into a power purchase agreement 
 with the requesting eligible customer-generator or eligible agricultural 
 customer-generator that is consistent with the minimum requirements for 
 contracts established by the Commission pursuant to subsection D. The power 
 purchase agreement shall obligate the supplier to purchase such excess 
 electricity at the rate that is provided for such purchases in a net metering 
 standard contract or tariff approved by the Commission, unless the parties 
 agree to a higher rate. The eligible customer-generator or eligible 
 agricultural customer-generator owns any renewable energy certificates 
 associated with its electrical generating facility; however, at the time that 
 the eligible customer-generator or eligible agricultural customer-generator 
 enters into a power purchase agreement with its supplier, the eligible 
 customer-generator or eligible agricultural customer-generator shall have a 
 one-time option to sell the renewable energy certificates associated with such 
 electrical generating facility to its supplier and be compensated at an amount 
 that is established by the Commission to reflect the value of such renewable 
 energy certificates. Nothing in this section shall prevent the eligible 
 customer-generator or eligible agricultural customer-generator and the supplier 
 from voluntarily entering into an agreement for the sale and purchase of excess 
 electricity or renewable energy certificates at mutually-agreed upon prices if 
 the eligible customer-generator or eligible agricultural customer-generator 
 does not exercise its option to sell its renewable energy certificates to its 
 supplier at Commission-approved prices at the time that the eligible 
 customer-generator or eligible agricultural customer-generator enters into a 
 power purchase agreement with its supplier. All costs incurred by the supplier 
 to purchase excess electricity and renewable energy certificates from eligible 
 customer-generators or eligible agricultural customer-generators shall be 
 recoverable through its Renewable Clean Energy Portfolio Standard (RPS) (CES) 
 rate adjustment clause, if the supplier has a Commission-approved RPS CES 
 plan. If not, then all costs shall be recoverable through the suppliers fuel 
 adjustment clause. For purposes of this section, "all costs" shall be 
 defined as the rates paid to the eligible customer-generator or eligible 
 agricultural customer-generator for the purchase of excess electricity and 
 renewable energy certificates and any administrative costs incurred to manage 
 the eligible customer-generators or eligible agricultural customer-generators 
 power purchase arrangements. The net metering standard contract or tariff shall 
 be available to eligible customer-generators or eligible agricultural 
 customer-generators on a first-come, first-served basis in each electric 
 distribution companys Virginia service area until the rated generating 
 capacity owned and operated by eligible customer-generators, eligible 
 agricultural customer-generators, and small agricultural generators in the 
 Commonwealth reaches one percent of each electric distribution companys 
 adjusted Virginia peak-load forecast for the previous year (the systemwide 
 cap), and shall require the supplier to pay the eligible customer-generator or 
 eligible agricultural customer-generator for such excess electricity in a 
 timely manner at a rate to be established by the Commission.
 
 
F. Any residential eligible customer-generator or eligible 
 agricultural customer-generator who owns and operates, or contracts with other 
 persons to own, operate, or both, an electrical generating facility with a 
 capacity that exceeds 10 kilowatts shall pay to its supplier, in addition to 
 any other charges authorized by law, a monthly standby charge. The amount of 
 the standby charge and the terms and conditions under which it is assessed 
 shall be in accordance with a methodology developed by the supplier and 
 approved by the Commission. The Commission shall approve a suppliers proposed 
 standby charge methodology if it finds that the standby charges collected from 
 all such eligible customer-generators and eligible agricultural 
 customer-generators allow the supplier to recover only the portion of the 
 suppliers infrastructure costs that are properly associated with serving such 
 eligible customer-generators or eligible agricultural customer-generators. Such 
 an eligible customer-generator or eligible agricultural customer-generator 
 shall not be liable for a standby charge until the date specified in an order 
 of the Commission approving its suppliers methodology.
 
 
G. On and after the later of July 1, 2019, or the effective 
 date of regulations that the Commission is required to adopt pursuant to � 
 56-594.01, (i) net energy metering in the service territory of each electric 
 cooperative shall be conducted as provided in a program implemented pursuant to 
 � 56-594.01 and (ii) the provisions of this section shall not apply to net 
 energy metering in the service territory of an electric cooperative except as 
 provided in � 56-594.01.
 
 
� 56-594.2. Small agricultural generators.
 
 
A. As used in this section:
 
 
"Small agricultural generating facility" means an 
 electrical generating facility that:
 
 
1. Has a capacity:
 
 
a. Of not more than 1.5 megawatts; and
 
 
b. That does not exceed 150 percent of the customers expected 
 annual energy consumption based on the previous 12 months of billing history or 
 an annualized calculation of billing history if 12 months of billing history is 
 not available;
 
 
2. Uses as its total source of fuel renewable energy;
 
 
3. Is located on the customers premises and is interconnected 
 with its utility through a separate meter;
 
 
4. Is interconnected and operated in parallel with an electric 
 utilitys distribution but not transmission facilities;
 
 
5. Is designed so that the electricity generated by the 
 facility is expected to remain on the utilitys distribution system; and
 
 
6. Is a qualifying small power production facility pursuant to 
 the Public Utility Regulatory Policies Act of 1978 (P.L. 95-617).
 
 
"Small agricultural generator" means a customer 
 that:
 
 
1. Is not an eligible agricultural customer-generator pursuant 
 to � 56-594;
 
 
2. Operates a small agricultural generating facility as part 
 of an agricultural business;
 
 
3. May be served by multiple meters that are located at 
 separate but contiguous sites;
 
 
4. May aggregate the electricity consumption measured by the 
 meters, solely for purposes of calculating 150 percent of the customers 
 expected annual energy consumption, but not for billing or retail service 
 purposes, provided that the same utility serves all of its meters;
 
 
5. Uses not more than 25 percent of contiguous land owned or 
 controlled by the agricultural business for purposes of the renewable energy 
 generating facility; and
 
 
6. Issues a certification under oath as to the amount of land 
 being used for renewable generation.
 
 
"Utility" includes supplier or distributor, as 
 applicable.
 
 
B. A small agricultural generator electing to interconnect 
 pursuant to this section shall:
 
 
1. Enter into a power purchase agreement with its utility to 
 sell all of the electricity generated from its small agricultural generating 
 facility, which power purchase agreement obligates the utility to purchase all 
 the electricity generated, at a rate agreed upon by the parties, but at a rate 
 not less than the utilitys Commission-approved avoided cost tariff for energy 
 and capacity;
 
 
2. Have the rights described in subsection E of � 56-594 
 pertaining to an eligible agricultural customer-generator as to the renewable 
 energy certificates or other environmental attributes generated by the 
 renewable energy generating facility;
 
 
3. Abide by the appropriate small generator interconnection 
 process as described in 20VAC5-314; and
 
 
4. Pay to its utility any necessary additional expenses as 
 required by this section.
 
 
C. Utilities:
 
 
1. Shall purchase, through the power purchase agreement 
 described in subdivision B 1, all of the output of the small agricultural 
 generator;
 
 
2. Shall recover the cost for its distribution facilities to 
 the generating meter either through a proportional cost-sharing agreement with 
 the small agricultural generator or through metering the total capacity and 
 energy placed on the distribution system by the small agricultural generator;
 
 
3. Shall recover all costs incurred by the utility to purchase 
 electricity, capacity, and renewable energy certificates from the small 
 agricultural generator:
 
 
a. If the utility has a Commission-approved Renewable Clean 
 Energy Portfolio Standard (RPS) (CES) 
 plan and rate adjustment clause, through the utilitys RPS CES rate adjustment clause; or
 
 
b. If the utility does not have a Commission-approved RPS CES 
 rate adjustment clause, through the utilitys fuel adjustment clause or through 
 the utilitys cost of purchased power;
 
 
4. May conduct settlement transactions for purchased power in 
 dollars on the small agricultural generators electric bill or through other 
 means of settlement, in the utilitys sole discretion;
 
 
5. Shall bill the small agricultural generator eligible costs 
 for small generator interconnection studies required pursuant to the 
 appropriate small generator interconnection process described in subdivision B 
 3; and
 
 
6. Shall bill its expenses, at cost, for any additional 
 engineering studies that a small agricultural generator is required to pay 
 prior to interconnection.
 
 
CHAPTER 
 29.
 
 
CARBON DIOXIDE 
 EMISSIONS FROM ELECTRICITY GENERATION.
 
 
� 56-614. Definitions. 
 
 
As used in this chapter, 
 unless the context requires a different meaning:
 
 
"Clean energy plan" 
 means a plan filed by an electric utility as 
 part of its integrated resource plan to reduce the electric utilitys 
 carbon dioxide emissions associated with electricity sales to the electric utilitys 
 electricity customers in accordance with the CES Goals established in 
 56-585.2 and that seeks to provide its 
 customers with energy generated from 100 percent 
 clean energy resources by 2050. 
 
 
"Clean energy 
 resource" has the meaning ascribed thereto in � 56-585.2. 
 
 
"Utility" has the 
 meaning ascribed thereto in � 56-585.2. 
 
 
� 56-615. Clean 
 energy targets. 
 
 
A. Each utility 
 shall meet the CES Goals established by � 56-585.2. 
 
 
B. By 2030, each utility 
 shall retire all coal-fired electric 
 generation facilities that it owns or operates that (i) are located 
 in the Commonwealth or (ii) serve the 
 electric utilitys Virginia load. 
 
 
� 56-616. Submission 
 and approval of plans. 
 
 
A. The first integrated resource 
 plan that a utility files with the Commission pursuant to 
 Chapter 24 (� 56-597 et seq.) after July 1, 2020, shall include a 
 clean energy plan that will achieve the CES Goals as set forth 
 in � 56-585.2 in 
 accordance with the following: 
 
 
1. The integrated resource 
 plan containing the clean energy plan shall utilize a 
 resource acquisition period that extends through 2030; 
 
 
2. The clean 
 energy plan submitted to the Commission shall set forth 
 a plan of actions and investments by the electric utility 
 projected to achieve compliance with the provisions of � 56-615 and that 
 result in an affordable, reliable, and clean electric system; 
 
 
3. The clean 
 energy plan shall clearly distinguish between the set of resources necessary to 
 meet customer demands in the resource acquisition period and the additional 
 clean energy plan activities that may be undertaken to meet the CES Goals as provided 
 in subsection A of � 
 56-615, which may create an additional resource need for 
 the clean energy plan. These activities may include retirement of existing 
 generating facilities, changes in system operation, or any other necessary 
 actions; 
 
 
4. After 
 conducting any procurement process, the utility shall set forth the actions and 
 investments required to fill the additional resource need identified for the 
 clean energy plan to satisfy the CES Goals as provided in 
 subsection A of � 56-615. These 
 actions and investments may include development of new clean energy resources, 
 development of new transmission and other supporting infrastructure, and clean 
 energy resource acquisitions; 
 
 
5. The clean 
 energy plan shall describe 
 the effect of the actions and investments included in the clean energy plan on 
 the safety, reliability, renewable energy integration, and resilience of 
 electric service in the Commonwealth; 
 
 
6. The clean 
 energy plan shall set forth the projected cost 
 of its implementation and anticipated reductions in carbon dioxide and other 
 emissions; 
 
 
7. If the 
 clean energy plan includes accelerated retirement of any existing generating 
 facilities, the clean energy plan shall include 
 workforce transition and community assistance plans for utility workers impacted 
 by any clean energy plan and a plan to pay community assistance to any local 
 government or school district, the voters of which have approved projects the 
 costs of which are expected to be paid for from property taxes that are 
 directly impacted by the accelerated retirement of the electric generating 
 facility in an amount equal to the costs of the voter-approved projects that 
 were expected to be paid from the revenue sources directly impacted by the 
 accelerated retirement of the projects, including the payment of bonds, notes, 
 or other multiple-fiscal year obligations or lease purchase agreements that 
 have been issued or entered into to pay the costs of such projects. Any payment 
 of community assistance shall be reduced on an equivalent basis to the extent 
 that property tax is derived from new electric infrastructure developed in the 
 same impacted community. The electric utility may 
 propose a cost-recovery mechanism to recover the prudently incurred costs of 
 any workforce transition and community assistance plans, while giving due 
 consideration to the impact on low-income customers. The electric utility shall not earn 
 its authorized rate of return on any noncapital costs incurred as part of any 
 workforce transition plan. The workforce transition and community assistance 
 plans shall include, to the extent 
 feasible, estimates of: 
 
 
a. The number 
 of workers employed by the utility or a contractor of the utility at the 
 electric generating facility; 
 
 
b. The total 
 number of existing workers with jobs that will be retained and the total number 
 of existing workers with jobs that will be eliminated due to the retirement of 
 the electric generating facility; 
 
 
c. With 
 respect to the existing workers with jobs that will be eliminated due to the 
 retirement of the electric generating facility, the total number and number by 
 job classification of workers for whom (i) employment 
 will end without being offered other employment by the utility; (ii) retirement will 
 occur as planned, early retirement will be 
 offered, or employment will end 
 voluntarily; (iii) jobs will be 
 retained via transfers to other 
 electric generating facilities or offers of other 
 employment by the utility; and (iv) retraining will 
 allow them to continue to work for the utility in a new job 
 classification; and
 
 
d. If the 
 utility is replacing the electric generating facility being retired with a new 
 electric generating facility, the number 
 of workers from the retired electric generating facility that will be offered 
 employment at the new electric generating facility and the number of jobs at 
 the new electric generating facility that will be outsourced to subcontractors. 
 The utility shall develop a training or apprenticeship program, under the terms 
 of an applicable collective bargaining agreement, if any, for the maintenance 
 and operation of any new combination generation and storage facility owned by 
 the utility that does not emit carbon dioxide, to which facility displaced 
 workers may transfer as appropriate. 
 
 
B. The Department 
 of Environmental Quality shall participate in any 
 proceeding seeking approval of a clean energy plan developed by a utility 
 pursuant to this section. The Department shall:
 
 
1. Describe the 
 methods of measuring carbon dioxide emissions and shall verify the projected 
 carbon dioxide emission reductions as a result of the clean energy plan; and
 
 
2. Determine 
 whether a clean energy plan as filed under this section will result in an 80 percent 
 reduction, relative to 2005 levels, in carbon dioxide emissions from the electric utilitys Virginia electricity 
 sales by 2030. The Department shall publish, and shall 
 report to the Commission, the Departments 
 calculation of carbon dioxide emission reductions attributable to any approved 
 clean energy plan. Nothing in the divisions engagement in this process shall 
 be construed to diminish or override the Commissions 
 authority under this title. 
 
 
C. The 
 Commission shall approve the clean energy plan if it finds it 
 to be in the public interest and consistent with the clean energy target in subsection 
 A of � 56-615. The Commission 
 may modify a proposed plan if the modification is 
 necessary to ensure that the plan is in the public interest. In evaluating 
 whether a clean energy plan submitted to the Commission 
 is in the public interest, the Commission 
 shall consider the following factors, among other relevant factors as defined 
 by the Commission: 
 
 
1. Reductions 
 in carbon dioxide and other emissions that will be achieved through the clean 
 energy plan and the environmental and health benefits of those reductions; 
 
 
2. The 
 feasibility of the clean energy plan and the clean energy plans impact on the 
 reliability and resilience of the electric system. The Commission 
 shall not approve any plan that does not protect electric system 
 reliability; and 
 
 
3. Whether 
 the clean energy plan will result in a reasonable cost to customers, as 
 evaluated on a net present value basis. In evaluating the cost impacts of the 
 clean energy plan, the Commission 
 shall consider the effect on customers of the projected costs associated with 
 the plan, as well as any projected 
 savings associated with the plan, including projected avoided fuel costs. 
 
 
D. If the Commission 
 finds that approval of the clean energy plan is not in the public interest, or 
 if the Commission modifies the plan, 
 the utility may choose to submit an amended plan to the Commission 
 for approval in lieu of having no plan or implementing the modified plan. No 
 clean energy plan is effective without Commission 
 approval. 
 
 
� 56-617. Closure of coal-fired generation 
 facilities. 
 
 
A. By January 1, 
 2030, each utility shall decommission 
 all of its coal-fired electric generation 
 facilities. 
 
 
B. The Commission 
 shall allow in electric rates all decommissioning 
 and remediation costs prudently incurred by an investor-owned 
 utility for a coal-fired generation facility. The Commission shall accelerate 
 depreciation schedules for any coal-fired generation facility to a date 
 no later than January 1, 2030. 
 
 
C. The Commission 
 may accelerate the depreciation schedule for any transmission line owned by an 
 investor-owned utility when the Commission 
 finds the transmission line is no longer used and useful as a result 
 of the decommissioning of a coal-fired generation 
 facility and there is no reasonable likelihood that the 
 transmission line will be utilized in the future. The adjusted depreciation 
 schedule shall require such a transmission 
 line to be fully depreciated on or 
 before January 1, 2030.