SB876: Electric utility regulation; mandatory clean energy standard program.
SENATE BILL NO. 876
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 utility's 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 utility's rates necessary to provide the opportunity to fully recover the costs of providing the utility's services and to earn not less than such combined rate of return. If the Commission finds that the utility's 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 utility's 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 utility's 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 Commission's 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 Moody's 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 utility's combined rate of return based on the Commission's consideration of the utility's 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 utility's cost of goods and services, the effect on the utility's 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 utility's 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 utility's 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 utility's 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 Commission's 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 utility's 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 utility's 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 utility's 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 Commission's staff in relation to that program that has bearing upon the Commission's 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 customer's premises if the customer provides, at the customer's 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 utility's 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 utility's 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 utility's 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 utility's 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 utility's distribution rate base, as such rate base was determined for the most recently ended 12-month test period in the utility's 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 utility's 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 Commission's 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 utility's 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 utility's 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 utility's 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 utility's 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 Commonwealth's Atlantic shoreline, regardless of whether any of such facilities are located within or without the utility's 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 utility's 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 utility's 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 utility's 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 Commission's 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 utility's general rate of return to calculate the enhanced rate of return on common equity, and the first portion of that facility's service life to which such enhanced rate of return shall be applied, shall vary by type of facility, as specified in the following table:
a
Type of Generation Facility
Basis Points
First Portion of Service Life
b
Nuclear-powered
200
Between 12 and 25 years
c
Carbon capture compatible, clean-coal powered
200
Between 10 and 20 years
d
Renewable powered, other than landfill gas powered
200
Between 5 and 15 years
e
Coalbed methane gas powered
150
Between 5 and 15 years
f
Landfill gas powered
200
Between 5 and 15 years
g
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 Commonwealth's 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 utility's 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 utility's 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 utility's 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 utility's 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 utility's 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 utility's 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 utility's 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 utility's rates for generation and distribution services. Any such costs shall remain combined with the utility's 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 Commission's 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 Commission's 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 utility's 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 Commission's rules governing utility rate increase applications as provided in subsection B. This provision shall not be deemed to change or reset base rates.
The Commission's 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 utility's 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 utility's other costs, revenues, and investments to be recovered through rates for generation and distribution services, result in the utility's 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 utility's other costs, revenues, and investments to be recovered through rates for generation and distribution services, cause the utility's 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 Commission's 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 utility's 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 utility's rates necessary to provide the opportunity to fully recover the costs of providing the utility's 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 Commission's 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 utility's 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 utility's 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 utility's rates ordered by the Commission pursuant to this subdivision shall not exceed $50 million in annual revenues, with any reduction allocated to the utility's 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 utility's 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 utility's 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 utility's 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 utility's 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 utility's rates for generation and distribution services over the service life of such facilities and shall not thereafter be included in the utility's 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 utility's rates for generation and distribution services over the service life of such facilities and shall be included in the utility's 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 utility's 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 utility's rates for generation and distribution services, may be the subject of a rate adjustment clause petition by the utility pursuant to subdivision 6.
The Commission's 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 utility's 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 utility's 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 Commission's 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 utility's rates pursuant to subdivision 8 a; (iv) revisions to the utility's rates pursuant to the Commission's 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 utility's 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 utility's 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 Commission's 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 utility's 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 Commission's 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 utility's understanding of emerging
energy technologies and their potential impact on and value to the utility's
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 utility's 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 utility's
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
utility's 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 utility's 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 utility's 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 utility's 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 utility's 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
utility's 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 facility's 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 customer's wiring on the customer's side of its interconnection with the distributor; (v) is interconnected and operated in parallel with an electric company's 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 customer's premises and is connected to the customer's wiring on the customer's side of its interconnection with the distributor; (iv) is interconnected and operated in parallel with an electric company's transmission and distribution facilities; and (v) is intended primarily to offset all or part of the customer's 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-generator's or eligible agricultural customer-generator's 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 Commission's 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-generator's 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 supplier's 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 supplier's 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 supplier's 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-generator's or eligible agricultural customer-generator's
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 company's 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 company's
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 supplier's 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 supplier's 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 supplier's 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 customer's 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 customer's premises and is interconnected with its utility through a separate meter;
4. Is interconnected and operated in parallel with an electric utility's distribution but not transmission facilities;
5. Is designed so that the electricity generated by the facility is expected to remain on the utility's 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 customer's 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 utility's 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 utility's RPS CES rate adjustment clause; or
b. If the utility does not have a Commission-approved RPS CES
rate adjustment clause, through the utility's fuel adjustment clause or through
the utility's cost of purchased power;
4. May conduct settlement transactions for purchased power in dollars on the small agricultural generator's electric bill or through other means of settlement, in the utility's 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.
§ 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 utility's carbon dioxide emissions associated with electricity sales to the electric utility's 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 utility's 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 utility's Virginia electricity sales by 2030. The Department shall publish, and shall report to the Commission, the Department's calculation of carbon dioxide emission reductions attributable to any approved clean energy plan. Nothing in the division's engagement in this process shall be construed to diminish or override the Commission's 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 plan's 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.