Va. Code Ann. § 56-585.1 — Virginia Code / Title 56 / Chapter 23 / Section 56-585.1
Generation, distribution, and transmission rates after capped rates terminate or expire
Status: in_force

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 biennial basis commencing in 2023, with such proceedings utilizing the two successive 12-month test periods ending December 31 immediately preceding the year in which such review proceeding is conducted. 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 review, as follows:

a. The Commission may use any methodology to determine such return it finds consistent with the public interest. However, for a Phase I Utility, for applications received by the Commission on or after January 1, 2020, such return shall not be set lower than the average of either (i) 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 or (ii) the authorized returns on common equity that are set by the applicable regulatory commissions for the same selected peer group, nor shall the Commission set such return more than 150 basis points higher than such average.

b. For a Phase I Utility, in selecting such majority of peer group investor-owned electric utilities for applications received by the Commission on or after January 1, 2020, the Commission shall first remove from such group the two utilities within such group that have the lowest reported or authorized, as applicable, returns of the group, as well as the two utilities within such group that have the highest reported or authorized, as applicable, 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. With respect to a Phase I Utility, for purposes of this subdivision 2, 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 review, and (iv) it is not an affiliate of the utility subject to such review or a utility whose fair rate of return on common equity is determined by the Commission.

c. The Commission may increase or decrease the utility's combined rate of return for generation and distribution services by up to 50 basis points based on factors that may include reliability, generating plant performance, customer service, and operating efficiency of a utility. Any such adjustment to the combined rate of return for generation and distribution services shall include consideration of nationally recognized standards determined by the Commission to be appropriate for such purposes.

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 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 and terminating thereafter. 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. After 2021, each Phase II Utility shall make a biennial filing by March 31 of every second year, except that the 2023 filing for a Phase II Utility shall be made on or after July 1, 2023. All biennial filings shall encompass the two successive 12-month test periods ending December 31 immediately preceding the year in which such review proceeding is conducted. All such filings shall consist of the schedules contained in the Commission's rules governing utility rate increase applications, 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. In a 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.

If the Commission determines that rates should be revised or credits be applied to customers' bills pursuant to subdivision 8 or 10, 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 specified in this paragraph, they shall thereafter be considered part of the utility's costs, revenues, and investments for the purposes of future review proceedings.

As of July 1, 2023, a Phase II Utility shall select a subset of rate adjustment clauses previously implemented pursuant to subdivision 5 or 6 having a combined annual revenue requirement, as of July 1, 2023, of at least $350 million and combine such rate adjustment clauses with the utility's costs, revenues, and investments for generation and distribution services. After such rate adjustment clauses are combined as specified in this paragraph, such rate adjustment clauses shall be considered part of the utility's costs, revenues, and investments for the purposes of future biennial review proceedings, and the combination of such rate adjustment clauses shall be specifically subject to audit by the Commission in the utility's 2023 biennial review filing. Notwithstanding the provisions of subsection C of § 56-581 , such combination shall not serve as the basis for an increase in a Phase II Utility's rates for generation and distribution services in its 2023 biennial proceeding.

4. 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.

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 or pilot 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 or pilot programs. Any such petition shall include a proposed budget for the design, implementation, and operation of the energy efficiency program, including anticipated savings from and spending on each program, and the Commission shall grant a final order on such petitions within eight months of initial filing. 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.

Energy efficiency pilot programs are in the public interest provided that the pilot program is (i) of limited scope, cost, and duration and (ii) intended to determine whether a new or substantially revised program would be cost-effective.

Prior to January 1, 2022, the Commission shall award a margin for recovery on operating expenses for energy efficiency programs and pilot programs, which margin shall be equal to the general rate of return on common equity determined as described in subdivision 2. Beginning January 1, 2022, and thereafter, if the Commission determines that the utility meets in any year the annual energy efficiency standards set forth in § 56-596.2 , in the following year, the Commission shall award a margin on energy efficiency program operating expenses in that year, to be recovered through a rate adjustment clause, which margin shall be equal to the general rate of return on common equity determined as described in subdivision 2. If the Commission does not approve energy efficiency programs that, in the aggregate, can achieve the annual energy efficiency standards, the Commission shall award a margin on energy efficiency operating expenses in that year for any programs the Commission has approved, to be recovered through a rate adjustment clause under this subdivision, which margin shall equal the general rate of return on common equity determined as described in subdivision 2. Any margin awarded pursuant to this subdivision shall be applied as part of the utility's next rate adjustment clause true-up proceeding. The Commission shall also award an additional 20 basis points for each additional incremental 0.1 percent in annual savings in any year achieved by the utility's energy efficiency programs approved by the Commission pursuant to this subdivision, beyond the annual requirements set forth in § 56-596.2 , provided that the total performance incentive awarded in any year shall not exceed 10 percent of that utility's total energy efficiency program spending in that same year.

The Commission shall annually monitor and report to the General Assembly the performance of all programs approved pursuant to this subdivision, including each utility's compliance with the total annual savings required by § 56-596.2 , as well as the annual and lifecycle net and gross energy and capacity savings, related emissions reductions, and other quantifiable benefits of each program; total customer bill savings that the programs produce; utility spending on each program, including any associated administrative costs; and each utility's avoided costs and cost-effectiveness results.

Notwithstanding any other provision of law, unless the Commission finds in its discretion and after consideration of all in-state and regional transmission entity resources that there is a threat to the reliability or security of electric service to the utility's customers, the Commission shall not approve construction of any new utility-owned generating facilities that emit carbon dioxide as a by-product of combusting fuel to generate electricity unless the utility has already met the energy savings goals identified in § 56-596.2 and the Commission finds that supply-side resources are more cost-effective than demand-side or energy storage resources.

As used in this subdivision, "large general service customer" means a customer that has a verifiable history of having used more than one megawatt of demand from a single site.

Large general service customers shall be exempt from requirements that they participate in energy efficiency programs if the Commission finds that the large general service customer has, at the customer's own expense, implemented energy efficiency programs that have produced or will produce measured and verified results consistent with industry standards and other regulatory criteria stated in this section. The Commission shall, no later than June 30, 2021, adopt rules or regulations (a) establishing the process for large general service customers to apply for such an exemption, (b) establishing the administrative procedures by which eligible customers will notify the utility, and (c) defining the standard criteria that shall be satisfied by an applicant in order to notify the utility, including means of evaluation measurement and verification and confidentiality requirements. At a minimum, such rules and regulations shall require that each exempted large general service customer certify to the utility and Commission that its implemented energy efficiency programs have delivered measured and verified savings within the prior five years. In adopting such rules or regulations, the Commission shall also specify the timing as to when a utility shall accept and act on such notice, taking into consideration the utility's integrated resource planning process, as well as its administration of energy efficiency programs that are approved for cost recovery by the Commission. Savings from large general service customers shall be accounted for in utility reporting in the standards in § 56-596.2 .

The notice of nonparticipation by a large general service customer shall be for the duration of the service life of the customer's energy efficiency measures. The Commission may on its own motion initiate steps necessary to verify such nonparticipant's achievement of energy efficiency if the Commission has a body of evidence that the nonparticipant has knowingly misrepresented its energy efficiency achievement.

A utility shall not charge such large general service customer 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 compliance with renewable energy portfolio standard requirements pursuant to § 56-585.5 that are not recoverable under subdivision 6. The Commission shall approve such a petition allowing the recovery of such costs incurred as required by § 56-585.5 , provided that the Commission does not otherwise find such costs were unreasonably or imprudently incurred;

e. Projected and actual costs of projects that the Commission finds to be necessary to mitigate impacts to marine life caused by construction of offshore wind generating facilities, as described in § 56-585.1:11 , or to comply with state or federal environmental laws or regulations applicable to generation facilities used to serve the utility's native load obligations, including the costs of allowances purchased through a market-based trading program for carbon dioxide emissions. The Commission shall approve such a petition if it finds that such costs are necessary to comply with such environmental laws or regulations;

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; and

g. Projected and actual costs, not currently in rates, for the utility to design, implement, and operate programs approved by the Commission to provide incentives to (i) low-income, elderly, and disabled individuals or (ii) organizations providing residential services to low-income, elderly, and disabled individuals for the installation of, or access to, equipment to generate electric energy derived from sunlight, provided the low-income, elderly, and disabled individuals, or organizations providing residential services to low-income, elderly, and disabled individuals, first participate in incentive programs for the installation of measures that reduce heating or cooling costs.

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 that emits carbon dioxide shall demonstrate that it has already met the energy savings goals identified in § 56-596.2 and that the identified need cannot be met more affordably through the deployment or utilization of demand-side resources or energy storage resources and 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. In any application to construct a new generating facility, the utility shall include, and the Commission shall consider, the social cost of carbon, as determined by the Commission, as a benefit or cost, whichever is appropriate. The Commission shall ensure that the development of new, or expansion of existing, energy resources or facilities does not have a disproportionate adverse impact on historically economically disadvantaged communities. The Commission may adopt any rules it deems necessary to determine the social cost of carbon and shall use the best available science and technology, including the Technical Support Document: Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866, published by the Interagency Working Group on Social Cost of Greenhouse Gases from the United States Government in August 2016, as guidance. The Commission shall include a system to adjust the costs established in this section with inflation.

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 16,100 megawatts, including rooftop solar installations with a capacity of not less than 50 kilowatts, and with an aggregate capacity of 100 megawatts, that use energy derived from sunlight or from onshore 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:

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.

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 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 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.

Notwithstanding any provision of Chapter 296 of the Acts of Assembly of 2018, construction, purchasing, or leasing activities for a new utility-owned and utility-operated generating facility or facilities utilizing energy derived from sunlight or from onshore wind with an aggregate capacity of 16,100 megawatts, including rooftop solar installations with a capacity of not less than 50 kilowatts, and with an aggregate capacity of 100 megawatts, together with a utility-owned and utility-operated generating facility or facilities utilizing energy derived from offshore wind with an aggregate capacity of not more than 3,000 megawatts, are in the public interest. Additionally, energy storage facilities with an aggregate capacity of 2,700 megawatts are in the public interest. To the extent that a utility elects to recover the costs of any such new generation or energy storage 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 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 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 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 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 § 45.2-1600 , 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 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. At any time, the Commission may, in its discretion, for a Phase I Utility, upon petition by such a utility or upon its own initiated proceeding, direct the consolidation of any one or more subsets of rate adjustment clauses previously implemented pursuant to subdivision 5 or 6 in the interest of judicial economy, customer transparency, or other factors the Commission determines to be appropriate. Any subset of rate adjustment clauses so consolidated shall continue to be considered by the Commission without regard to the other costs, revenues, investments, or earnings of the utility and remain as a cost recovery mechanism independent from the utility's rates for generation and distribution services pursuant to § 56-585.8 and subdivisions 5 and 6, but will be combined as a single rate adjustment clause for cost recovery and review purposes. Any rate adjustment clause or subset of rate adjustment clauses so consolidated shall be named in a manner, as determined by the Commission, that reasonably informs customers as to the nature of the costs recovered by the consolidated rate adjustment clause.

At any time, the Commission may, in its discretion, for a Phase II Utility, upon petition by such a utility or upon its own initiated proceeding, direct the consolidation of any one or more subsets of rate adjustment clauses previously implemented pursuant to subdivision 5 or 6 in the interest of judicial economy, customer transparency, or other factors the Commission determines to be appropriate. Any subset of rate adjustment clauses so consolidated shall continue to be considered by the Commission without regard to the other costs, revenues, investments, or earnings of the utility and remain as a cost recovery mechanism independent from the utility's rates for generation and distribution services pursuant to this subdivision and subdivisions 5 and 6, but will be combined as a single rate adjustment clause for cost recovery and review purposes. Any rate adjustment clause or subset of rate adjustment clauses so consolidated shall be named in a manner, as determined by the Commission, that reasonably informs customers as to the nature of the costs recovered by the consolidated rate adjustment clause.

8. For a Phase I Utility in any triennial review proceeding filed on or before June 30, 2023 or for a Phase II Utility in any biennial 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 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. Notwithstanding the prior sentence, the aggregate amount of actual and reasonable costs associated with severe weather events eligible for such deferral 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 for the combined test periods under review. For the purposes of determining any amount of costs that are associated with severe weather events, the Commission shall consider nationally recognized standards such as those published by the Institute of Electrical and Electronics Engineers (IEEE). 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 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 any triennial review initiated prior to July 1, 2023 that:

a. Revenue reductions related to energy efficiency measures or programs approved and deployed since the utility's previous triennial review have caused the utility, as verified by the Commission, during the test period or periods under review, considered as a whole, to earn 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 for generation and distribution services necessary to recover such revenue reductions. If the Commission finds, for reasons other than revenue reductions related to energy efficiency measures, that 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. 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 10 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 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 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 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 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.

e. In any biennial review of a Phase II Utility, the Commission's final order regarding such 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 review shall apply, for purposes of reviewing the utility's earnings on its rates for generation and distribution services, to the entire two or three, as applicable, successive 12-month test periods ending December 31 immediately preceding the year of the utility's subsequent 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 review proceeding, utilizing rate adjustment clause true-up protocols as the Commission in its discretion may determine.

9. a. In any biennial review for a Phase II Utility filed on or prior to December 31, 2023, if the Commission determines that the utility has during the test period or test periods under review, considered as a whole, earned more than 70 basis points above a fair combined rate of return on its generation and distribution services previously authorized by the Commission, 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, which have not been combined with the utility's costs, revenues, and investments for generation and distribution services, the Commission shall direct that 85 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, 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.

b. In any biennial review for a Phase II Utility filed on or after January 1, 2024, if the Commission determines that the utility has during the test period or test periods under review, considered as a whole, earned above its fair combined rate of return on its generation and distribution services previously authorized by the Commission, 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, which have not been combined with the utility's costs, revenues, and investments for generation and distribution services, the Commission shall direct that 85 percent of the amount of such earnings above such fair combined rate of return for the test period or periods under review, considered as a whole, be credited to customers' bills. Further, if the Commission determines that during the test period or test periods under review, considered as a whole, a Phase II Utility earned more than 150 basis points above a fair combined rate of return on its generation and distribution services previously authorized by the Commission, without regard to any return on common equity or other matters determined with respect to facilities described in subdivision 6, which have not been combined with the utility's costs, revenues, and investments for generation and distribution services, the Commission shall direct that all such earnings that were more than 150 basis points above such fair combined rate of return for the test period or periods under review, considered as a whole, 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.

10. 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.

11. 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 Clean Energy Policy set forth in § 45.2-1706.1, and shall also consider whether the costs of such resources is likely to result in unreasonable increases in rates paid by customers.

E. Notwithstanding any other provision of law, the Commission shall determine the amortization period for recovery of any appropriate costs due to the early retirement of any electric generation facilities owned or operated by any Phase I Utility or Phase II Utility. In making such determination, the Commission shall (i) perform an independent analysis of the remaining undepreciated capital costs; (ii) establish a recovery period that best serves ratepayers; and (iii) allow for the recovery of any carrying costs that the Commission deems appropriate.

F. The Commission shall include in its report required by subsection B of § 56-596 any information concerning the reliability impacts of generation unit additions and retirement determinations by a Phase I or Phase II Utility, along with the potential impact on the purchase of power from generation assets outside the Virginia jurisdiction used to serve the utility's native load, utilizing information from the respective utility's integrated resource plan or information from the respective utility's plan filed pursuant to subsection D of § 56-585.5.

G. The Commission shall promulgate such rules and regulations as may be necessary to implement the provisions of this section.

2007, cc. 888 , 933 ; 2008, c. 476 ; 2009, c. 824 ; 2011, cc. 236 , 367 , 371 , 380 , 382 ; 2012, c. 435 ; 2013, c. 2 ; 2014, cc. 212 , 541 , 548 , 550 ; 2015, cc. 37 , 599 ; 2016, c. 3 ; 2017, cc. 246 , 564 , 583 , 820 ; 2018, cc. 296 , 795 ; 2019, cc. 535 , 741 , 773 ; 2020, cc. 662 , 799 , 801 , 1108 , 1190 , 1193 , 1194 ; 2021, Sp. Sess. I, c. 327 ; 2023, cc. 704 , 705 , 749 , 757 , 775 , 776 .
Va. Code Ann. § 56-46.1 — Virginia Code / Title 56 / Chapter 1 / Article 6 / Section 56-46.1
Commission to consider environmental, economic, and improvements in service reliability factors in approving construction of electrical utility facilities; approval required for construction of certain electrical transmission lines; notice and hearings
Status: in_force

A. Whenever the Commission is required to approve the construction of any electrical utility facility, it shall give consideration to the effect of that facility on the environment and establish such conditions as may be desirable or necessary to minimize adverse environmental impact. In order to avoid duplication of governmental activities, any valid permit or approval required for an electric generating plant and associated facilities issued or granted by a federal, state, or local governmental entity charged by law with responsibility for issuing permits or approvals regulating environmental impact and mitigation of adverse environmental impact or for other specific public interest issues such as building codes, transportation plans, and public safety, whether such permit or approval is granted prior to or after the Commission's decision, shall be deemed to satisfy the requirements of this section with respect to all matters that (i) are governed by the permit or approval or (ii) are within the authority of, and were considered by, the governmental entity in issuing such permit or approval, and the Commission shall impose no additional conditions with respect to such matters. Nothing in this section shall affect the ability of the Commission to keep the record of a case open. Nothing in this section shall affect any right to appeal such permits or approvals in accordance with applicable law. In the case of a proposed facility located in a region that was designated as of July 1, 2001, as serious nonattainment for the one-hour ozone standard as set forth in the federal Clean Air Act, the Commission shall not issue a decision approving such proposed facility that is conditioned upon issuance of any environmental permit or approval. In every proceeding under this subsection, the Commission shall receive and give consideration to all reports that relate to the proposed facility by state agencies concerned with environmental protection; and if requested by any county or municipality in which the facility is proposed to be built, to local comprehensive plans that have been adopted pursuant to Article 3 (§ 15.2-2223 et seq.) of Chapter 22 of Title 15.2. Additionally, the Commission (a) shall consider the effect of the proposed facility on economic development within the Commonwealth, including but not limited to furtherance of the economic and job creation objectives of the Commonwealth Clean Energy Policy set forth in § 45.2-1706.1 , and (b) shall consider any improvements in service reliability that may result from the construction of such facility.

B. Subject to the provisions of subsection J, no electrical transmission line of 138 kilovolts or more shall be constructed unless the State Corporation Commission shall, after at least 30 days' advance notice by (i) publication in a newspaper or newspapers of general circulation in the counties and municipalities through which the line is proposed to be built, (ii) written notice to the governing body of each such county and municipality, and (iii) causing to be sent a copy of the notice by first class mail to all owners of property within the route of the proposed line, as indicated on the map or sketch of the route filed with the Commission, which requirement shall be satisfied by mailing the notice to such persons at such addresses as are indicated in the land books maintained by the commissioner of revenue, director of finance or treasurer of the county or municipality, approve such line. Such notices shall include a written description of the proposed route the line is to follow, as well as a map or sketch of the route including a digital geographic information system (GIS) map provided by the public utility showing the location of the proposed route. The Commission shall make GIS maps provided under this subsection available to the public on the Commission's website. Such notices shall be in addition to the advance notice to the chief administrative officer of the county or municipality required pursuant to § 15.2-2202 .

As a condition to approval the Commission shall determine that the line is needed and that the corridor or route chosen for the line will avoid or reasonably minimize adverse impact to the greatest extent reasonably practicable on dwelling houses and on the scenic assets, historic and cultural resources recorded with the Department of Historic Resources, cultural resources identified by federally recognized Tribal Nations in the Commonwealth, and environment of the area concerned. To assist the Commission in this determination, as part of the application for Commission approval of the line, the applicant shall summarize its efforts to avoid or reasonably minimize adverse impact to the greatest extent reasonably practicable on dwelling houses and on the scenic assets, historic resources recorded with the Department of Historic Resources, and environment of the area concerned. In making the determinations about need, corridor or route, and method of installation, the Commission shall verify the applicant's load flow modeling, contingency analyses, and reliability needs presented to justify the new line and its proposed method of installation. If the local comprehensive plan of an affected county or municipality designates corridors or routes for electric transmission lines and the line is proposed to be constructed outside such corridors or routes, in any hearing the county or municipality may provide adequate evidence that the existing planned corridors or routes designated in the plan can adequately serve the needs of the company. Additionally, the Commission shall consider, upon the request of the governing body of any county or municipality in which the line is proposed to be constructed, (a) the costs and economic benefits likely to result from requiring the underground placement of the line and (b) any potential impediments to timely construction of the line. For new overhead transmission lines of 500 kilovolts or more constructed by a Phase II Utility, as that term is defined in subdivision A 1 of § 56-585.1 , the Commission shall prioritize approving corridors or routes for construction pursuant to this subsection for which the center of such corridor or route is located farther than 150 feet from any dwelling house, public or private school building, day care, or place of worship building unless no other practicable alternative exists.

C. If, prior to such approval, any interested party shall request a public hearing, the Commission shall, as soon as reasonably practicable after such request, hold such hearing or hearings at such place as may be designated by the Commission. In any hearing, the public service company shall provide adequate evidence that existing rights-of-way cannot adequately serve the needs of the company.

If, prior to such approval, written requests therefor are received from the governing body of any county or municipality through which the line is proposed to be built or from 20 or more interested parties, the Commission shall hold at least one hearing in the area that would be affected by construction of the line, for the purpose of receiving public comment on the proposal. If any hearing is to be held in the area affected, the Commission shall direct that a copy of the transcripts of any previous hearings held in the case be made available for public inspection at a convenient location in the area for a reasonable time before such local hearing.

D. As used in this section, unless the context requires a different meaning:

"Environment" or "environmental" shall be deemed to include in meaning "historic," as well as a consideration of the probable effects of the line on the health and safety of the persons in the area concerned.

"Interested parties" includes the governing bodies of any counties or municipalities through which the line is proposed to be built and persons residing or owning property in each such county or municipality.

"Public utility" means a public utility as defined in § 56-265.1 .

"Qualifying facilities" means a cogeneration or small power production facility that meets the criteria of 18 C.F.R. Part 292.

"Reasonably accommodate requests to wheel or transmit power" means:

1. That the applicant will make available to new electric generation facilities constructed after January 9, 1991, qualifying facilities and other nonutilities, a minimum of one-fourth of the total megawatts of the additional transmission capacity created by the proposed line, for the purpose of wheeling to public utility purchasers the power generated by such qualifying facilities and other nonutility facilities which are awarded a power purchase contract by a public utility purchaser in compliance with applicable state law or regulations governing bidding or capacity acquisition programs for the purchase of electric capacity from nonutility sources, provided that the obligation of the applicant will extend only to those requests for wheeling service made within the 12 months following certification by the State Corporation Commission of the transmission line and with effective dates for commencement of such service within the 12 months following completion of the transmission line; and

2. That the wheeling service offered by the applicant, pursuant to subdivision 1, will reasonably further the purposes of the Public Utilities Regulatory Policies Act of 1978 (P. L. 95-617), as demonstrated by submitting to the Commission, with its application for approval of the line, the cost methodologies, terms, conditions, and dispatch and interconnection requirements the applicant intends, subject to any applicable requirements of the Federal Energy Regulatory Commission, to include in its agreements for such wheeling service.

E. In the event that, at any time after the giving of the notice required in subsection B, it appears to the Commission that consideration of a route or routes significantly different from the route described in the notice is desirable, the Commission shall cause notice of the new route or routes to be published and mailed in accordance with subsection B. The Commission shall thereafter comply with the provisions of this section with respect to the new route or routes to the full extent necessary to give affected localities, federally recognized Tribal Nations in the Commonwealth, and interested parties in the newly affected areas the same protection afforded to affected localities and interested parties affected by the route described in the original notice.

F. Approval of a transmission line pursuant to this section shall be deemed to satisfy the requirements of § 15.2-2232 and local zoning ordinances with respect to such transmission line.

G. The Commission shall enter into a memorandum of agreement with the Department of Environmental Quality regarding the coordination of their reviews of the environmental impact of electric generating plants and associated facilities. If the proposed plants or associated facilities are in a locality identified by the Ombudsman for Tribal Consultation pursuant to subdivision B 2 of § 2.2-401.01 , such consultation information shall be included in the memorandum of agreement.

H. An applicant that is required to obtain (i) a certificate of public convenience and necessity from the Commission for any electric generating facility, electric transmission line, natural or manufactured gas transmission line as defined in 49 C.F.R. § 192.3, or natural or manufactured gas storage facility (hereafter, an energy facility) and (ii) an environmental permit for the energy facility that is subject to issuance by any agency or board within the Secretariat of Natural and Historic Resources, may request a pre-application planning and review process. In any such request to the Commission or the Secretariat of Natural and Historic Resources, the applicant shall identify the proposed energy facility for which it requests the pre-application planning and review process. The Commission, the Department of Environmental Quality, the Marine Resources Commission, the Department of Wildlife Resources, the Department of Historic Resources, the Department of Conservation and Recreation, and other appropriate agencies of the Commonwealth shall participate in the pre-application planning and review process. Participation in such process shall not limit the authority otherwise provided by law to the Commission or other agencies or boards of the Commonwealth. The Commission and other participating agencies and boards of the Commonwealth may invite federal and local governmental entities charged by law with responsibility for issuing permits or approvals and potentially impacted federally recognized Tribal Nations in the Commonwealth to participate in the pre-application planning and review process. Through the pre-application planning and review process, the applicant, the Commission, participating agencies and boards of the Commonwealth, and potentially impacted federally recognized Tribal Nations in the Commonwealth shall identify the potential impacts and approvals that may be required and shall develop a plan that will provide for an efficient and coordinated review of the proposed energy facility. The plan shall include (a) a list of the permits or other approvals likely to be required based on the information available, (b) a specific plan and preliminary schedule for the different reviews, (c) a plan for coordinating those reviews and the related public comment process, and (d) designation of points of contact, either within each agency or for the Commonwealth as a whole, to facilitate this coordination. The plan shall be made readily available to the public and shall be maintained on a dedicated website to provide current information on the status of each component of the plan and each approval process including opportunities for public comment.

I. The provisions of this section shall not apply to the construction and operation of a small renewable energy project, as defined in § 10.1-1197.5 , by a utility regulated pursuant to this title for which the Department of Environmental Quality has issued a permit by rule pursuant to Article 5 (§ 10.1-1197.5 et seq.) of Chapter 11.1 of Title 10.1.

J. Approval under this section shall not be required for any transmission line for which a certificate of public convenience and necessity is not required pursuant to subdivision A of § 56-265.2 .

1972, c. 652; 1973, c. 307; 1974, c. 498; 1983, c. 438; 1984, cc. 287, 562; 1985, c. 282; 1991, cc. 90, 148; 1996, c. 254 ; 2001, c. 758 ; 2002, c. 483 ; 2007, cc. 756 , 761 , 776 , 825 ; 2009, cc. 808 , 854 ; 2011, cc. 236 , 243 ; 2012, cc. 54 , 284 ; 2016, cc. 192 , 276 ; 2020, cc. 450 , 958 ; 2021, Sp. Sess. I, c. 327 ; 2024, c. 830 ; 2026, c. 866 .
Va. Code Ann. § 56-585.1:3 — Virginia Code / Title 56 / Chapter 23 / Section 56-585.1:3
Pilot programs for community solar development
Status: in_force

A. As used in this section:

"Eligible generation facility" means an electrical generation facility that:

1. Exclusively uses energy derived from sunlight;

2. Is placed in service on or after July 1, 2017;

3. Is not constructed by an investor-owned utility and either (i) is acquired by an investor-owned utility through an asset purchase agreement or (ii) is subject to a power purchase agreement under which an investor-owned utility purchases the facility's output from a third party; and

4. Has a generating capacity of:

a. Not more than two megawatts; or

b. More than two megawatts if not more than two megawatts of the output from the electrical generation facility is selected in an investor-owned utility's RFP for dedication to its pilot program.

"Generating capacity" means an electrical generation facility's nameplate rated capacity measured in direct current megawatts.

"Investor-owned utility" means an electric utility that is a Phase I Utility or a Phase II Utility.

"Low-income community" means a census tract within the Commonwealth designated by the U.S. Department of Housing and Urban Development in 2019 or any year thereafter as a qualified census tract for purposes of the Low-Income Housing Tax Credit pursuant to § 42 of the Internal Revenue Code.

"Participating generating facility" means an eligible generation facility that is selected by an investor-owned utility through its RFP for inclusion in its pilot program.

"Participating third party" means, for investor-owned utilities, a Virginia nonresidential-class customer, an affiliate, a solar development entity, or a nonjurisdictional customer that takes on the obligation, as part of a variable-output contract, of pilot program costs not recovered through the voluntary companion rate schedule as specified in subdivision B 8.

"Participating utility" means (i) each investor-owned utility and (ii) any utility consumer services cooperative that elects to conduct a pilot program under subsection C.

"Phase I Utility" means 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.

"Phase II Utility" means an investor-owned incumbent electric utility that was, as of July 1, 1999, bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002.

"Pilot program" means a community solar pilot program conducted by a participating utility pursuant to this section following approval by the Commission, under which the participating utility sells electric power to subscribing customers under a voluntary companion rate schedule and the participating utility generates or purchases electric power from participating generation facilities selected by the participating utility.

"Pilot program costs" means all of a participating utility's identified, projected, and actual costs of its pilot program, including costs for (i) purchased power; (ii) renewable and other environmental attributes; (iii) transmission and distribution services; (iv) generating capacity and energy balancing; (v) RFP process costs; (vi) administrative and marketing charges; (vii) capital costs and operations and maintenance expenses related to building, owning, and operating eligible generating facilities; and (viii) a reasonable margin, which margin shall be the weighted average cost of capital.

"Pilot program period" means the three-year period ending three years following the date the first subscription is entered into by a customer.

"RFP" means the request for proposal process conducted by an investor-owned utility.

"Small eligible generation facility" means an eligible generation facility with a generating capacity of less than 0.5 megawatt.

"Solar development entity" means a business entity organized primarily for the purpose of proposing, developing, constructing, purchasing, or selling at wholesale all or part of the output of an eligible generation facility. A solar development entity may be organized in any form and may be a special purpose entity.

"Utility aggregation cooperative" has the same meaning ascribed to "cooperative" in § 56-231.38 .

"Utility consumer services cooperative" has the same meaning ascribed to "cooperative" in § 56-231.15 .

"Voluntary companion rate schedule" means a rate schedule approved by the Commission upon application by a participating utility that provides for the recovery of the pilot program costs by the participating utility.

B. Notwithstanding the provisions of subsection B of § 56-234 and §§ 56-249.6 and 56-585.1 , each investor-owned utility shall conduct a pilot program for retail customers as follows:

1. Each investor-owned utility shall design its own pilot program and within six months of receiving Commission approval shall make subscriptions for participation in its pilot program available to its retail customers on a voluntary basis.

2. An investor-owned utility shall select eligible generating facilities for dedication to its pilot program through an RFP process, under which process:

a. Each investor-owned utility shall have issued one or more public RFPs for eligible generating facilities and the purchase of all energy output and associated renewable energy certificates and other environmental attributes.

b. Each RFP shall:

(1) State the price and non-price criteria used by the investor-owned utility in selecting proposals for dedication to its pilot program; and

(2) Require as a criterion for selection that eligible generating facilities with a combined generating capacity of not less than two megawatts, and any eligible generating facility with a generating capacity of more than two megawatts, be first placed in service on or after July 1, 2017.

c. Each investor-owned utility is authorized to select, under an asset purchase or power purchase agreement, small eligible generating facilities for dedication to its pilot program without regard to whether price criteria are satisfied by their selection if the selection of the small eligible generating facilities (i) materially advances non-price criteria, including a criterion favoring geographic distribution of eligible generating facilities, provided that the generating capacity of small eligible generating facilities does not exceed 25 percent of the utility's pilot program's minimum generating capacity specified in subdivision 3, or (ii) is located in a low-income community as provided in subdivision 15.

d. An investor-owned utility shall not select through its RFP an electrical generation facility with a generating capacity of more than two megawatts for its pilot program unless (i) the costs can be appropriately documented for the portion of the facility's output, which portion shall not exceed two megawatts, that is dedicated to the pilot program and (ii) for a Phase II Utility only, the portion of the facility's generating capacity selected pursuant to this subdivision does not exceed 50 percent of the investor-owned utility's pilot program's minimum generating capacity specified in subdivision 3. The portion of the facility's generating capacity that exceeds the portion of the facility's generating capacity that is selected pursuant to this subdivision shall not be applied in determining whether the pilot program satisfies requirements of subdivision 3 regarding a pilot program's minimum generating capacity.

e. In selecting eligible generating facilities for dedication to its pilot program, an investor-owned utility shall give due consideration to relative costs, economic development benefits, and geographic diversity of eligible generating facilities and ensure that the selection of such facilities complies with the requirements of subdivision 15 regarding the location of eligible generating facilities in low-income communities.

f. The investor-owned utility's application to the Commission shall include a description of the application of the price and non-price criteria in the investor-owned utility's selection of participating generating facilities from among the proposals submitted in response to the RFP.

3. The amount of generating capacity of the eligible generating facilities in an investor-owned utility's pilot program shall not be less than (i) 0.5 megawatt if the pilot program is conducted by a Phase I Utility or (ii) 10 megawatts if the pilot program is conducted by a Phase II Utility.

4. The amount of generating capacity of the eligible generating facilities in an investor-owned utility's pilot program shall not exceed (i) 10 megawatts if the pilot program is conducted by a Phase I Utility or (ii) 40 megawatts if the pilot program is conducted by a Phase II Utility.

5. An investor-owned utility shall have the option of increasing the amount of generating capacity of the eligible generating facilities in its pilot program above the amount most recently approved by the Commission, in such increments as the investor-owned utility elects, as follows:

a. Any such increase shall not result in an amount of generating capacity that exceeds the cap specified for the investor-owned utility's pilot program under subdivision 4;

b. No such increase shall be authorized until such time that 90 percent of the amount of generating capacity of the eligible generating facilities then approved for its pilot program has been subscribed by customers through the investor-owned utility's voluntary companion rate schedule;

c. An investor-owned utility may seek any number of increases in the amount of generating capacity of the eligible generating facilities in its pilot program, subject to the conditions in subdivisions a and b; and

d. The investor-owned utility shall select eligible generating facilities for any increase in the generating capacity of its pilot program through an RFP process that complies with the requirements of subdivision 2.

6. Each pilot program shall expire at the end of its pilot program period, unless renewed or made permanent as provided in subsection G.

7. The renewable energy certificates and other environmental attributes associated with the voluntary companion rate schedule shall be retired by the investor-owned utility on the subscribing customer's behalf.

8. An investor-owned utility shall recover all its pilot program costs primarily through its voluntary companion rate schedule. However, pilot program costs that are not recovered through the voluntary companion rate schedule shall be recoverable from a participating third party and not from the investor-owned utility's Virginia jurisdictional customers. To the extent participating third parties are obligated for pilot program costs not recovered through the voluntary companion rate schedule, variable-output contracts between participating third parties other than affiliates and investor-owned utilities shall be negotiated at arm's length and shall not be reviewable by the Commission and shall require no further Commission approvals pursuant to Chapter 4 (§ 56-76 et seq.) or other applicable law.

9. At the conclusion of the pilot program period, to the extent that the pilot program is not made permanent or extended, each participating generating facility shall cease to be part of the pilot program and shall return to operation under the variable-output contract with a participating third party.

10. Any fixed generation costs and fixed purchased power costs shall remain fixed for subscribing customers throughout the duration of the subscribing customers' continuous and uninterrupted participation in the voluntary companion rate schedule. A subscribing customer's participation in the voluntary companion rate schedule shall be deemed to be continuous and uninterrupted notwithstanding a change in the location where the customer receives service if the new location continues to be within the investor-owned utility's service territory and the customer provides the investor-owned utility with notice of the change prior to or within 90 days following the change. Investor-owned utilities are authorized to decrease the generation or purchased power rate, or both, at any time to reflect cost reductions, if any, subject to Commission review. If, pursuant to subdivision 9, the pilot program is not made permanent or continued, the subscribing customers' subscriptions to the voluntary companion rate schedule shall survive the termination of the pilot program.

11. A subscribing customer's usage that exceeds the amount subscribed for under the voluntary companion rate schedule shall be billed under the customer's applicable standard rate.

12. An investor-owned utility shall not require a subscribing customer to enter an agreement or subscription for participation in a pilot program of more than 12 months' duration unless the subscribing customer's subscription exceeds 100 kW, or its equivalent in kWh, at the time the customer initially enters into the agreement or subscription.

13. As part of an arrangement with a solar development entity, a utility may enter into an agreement that provides for risk sharing and collaboration in marketing a utility's pilot program if the solar development entity is a participating third party.

14. An investor-owned utility shall have the ability to close its pilot program to new subscribers according to the terms of the voluntary companion rate schedule upon notice to the Commission. This option shall be exercisable once per year, upon the anniversary date of the Commission's order approving the voluntary companion rate schedule.

15. Notwithstanding any provision of this section to the contrary, effective July 1, 2020, an investor-owned utility shall not select an eligible generating facility that is located outside a low-income community for dedication to its pilot program unless the investor-owned utility contemporaneously selects for dedication to its pilot program one or more eligible generating facilities that are located within a low-income community and of which the pilot program costs equal or exceed the pilot program costs of the eligible generating facility that is located outside a low-income community.

C. Notwithstanding the provisions of subsection B of § 56-234 and §§ 56-249.6 and 56-585.1 , upon application of a utility consumer services cooperative the Commission shall review a proposal submitted by the cooperative for a voluntary companion rate schedule. If the Commission finds that the proposal is reasonable and prudent, it shall approve the voluntary companion rate schedule for the cooperative to conduct a pilot program pursuant to this section. No utility consumer services cooperative shall be required to conduct a pilot program pursuant to this section. In making an application to the Commission pursuant to this subsection, a utility consumer services cooperative shall have flexibility to design its voluntary companion rate schedule in a manner that, notwithstanding anything to the contrary in this section, provides the cooperative the ability to:

1. Construct or purchase its generating facilities, or dedicate a portion of its existing power supply portfolio, for its community solar pilot program along with one or more other utility consumer services cooperatives, one or both Phase I or Phase II Utilities, or a utility aggregation cooperative, through requests for proposal or through a contract with a third party or a utility aggregation cooperative;

2. If constructing or purchasing its generating facilities, or dedicating a portion of its existing power supply portfolio, for its pilot program through a utility aggregation cooperative, include generating facilities that may be already in service or may be first placed into service at any time;

3. Utilize generating facilities of any generating capacity for its pilot program;

4. Physically locate the generating facilities used for the pilot program inside or outside of its certificated service territory;

5. Design its voluntary companion rate schedule in coordination with one or more utility consumer services cooperatives, such that participating subscribers from both cooperatives subscribe to an identical rate schedule;

6. Permanently end its pilot program for all subscribers according to the terms of the voluntary companion rate schedule; and

7. Recover pilot program costs that are not recovered through the voluntary companion rate schedule by including unrecovered purchased power expense in the cooperative's cost of purchased power and through a regulatory asset for unrecovered costs that are not purchased power expense, subject to the oversight of the cooperative's board of directors, which regulatory asset shall be approved by the Commission.

D. The participation of retail customers in a pilot program administered by a participating utility in the Commonwealth is in the public interest. Voluntary companion rate schedules approved by the Commission pursuant to this section are necessary in order to acquire information which is in furtherance of the public interest. The Commission shall approve the recovery of pilot program costs that it deems to be reasonable and prudent. The Commission shall also approve the pilot program design, the voluntary companion rate schedule, and the portfolio of participating generating facilities. No Commission review or approval of individual participating generating facilities, agreements, sites, or RFPs shall be required pursuant to this section or any other section of the Code.

E. Any voluntary companion rate schedule approved by the Commission pursuant to this section shall not be considered a tariff for electric energy provided 100 percent from renewable energy pursuant to § 56-577 .

F. Each participating utility shall report on the status of its pilot program, including the number of subscribing customers, to the Governor, the Commission, and the Chairmen of the House Committee on Labor and Commerce and the Senate Committee on Commerce and Labor. The report shall be filed the earlier of (i) three years after the date a customer of the participating utility first subscribes to its pilot program or (ii) July 1, 2022. If a participating utility closes its pilot program to new subscribers pursuant to subdivision B 14, it shall notify the Governor, the Commission, and the Chairmen of the House Committee on Labor and Commerce and the Senate Committee on Commerce and Labor not later than three months after such closure, which notification shall (a) describe the reasons for the closure and (b) be provided in lieu of the status report otherwise required by this subsection.

G. At any time after filing its report on the status of its pilot program as required by subsection F, a participating utility may, in its application proceeding, move the Commission to make its pilot program permanent. The motion shall include a compliance filing with conforming changes to the participating utility's applicable rate schedules. Upon the Commission's granting of the motion, the pilot program shall become a regular rate schedule of the participating utility.

2017, c. 580 ; 2019, cc. 742 , 763 ; 2020, c. 663 .
Va. Code Ann. § 56-484.21 — Virginia Code / Title 56 / Chapter 15 / Article 8 / Section 56-484.21
Instructions for emergency calling
Status: in_force

Commencing July 1, 2009, the MLTS provider of any multiline telephone system shall either (i) demonstrate or provide written instructions to each new user of the MLTS how to place an emergency call from a telephone station or (ii) provide written instructions at each telephone station that inform an individual how to place an emergency call from the telephone station. Written instructions provided to a new user or provided at a telephone station shall include the telephone station's street address and such additional information regarding the location of the telephone station that is sufficiently specific to permit an emergency responder with the information to locate the telephone station.

2007, c. 427 .
Va. Code Ann. § 56-585.1:4 — Virginia Code / Title 56 / Chapter 23 / Section 56-585.1:4
Development of solar and wind generation and energy storage capacity in the Commonwealth
Status: in_force

A. Prior to January 1, 2024, (i) the construction or purchase by a public utility of one or more solar or wind generation facilities located in the Commonwealth or off the Commonwealth's Atlantic shoreline, each having a rated capacity of at least one megawatt and having in the aggregate a rated capacity that does not exceed 5,000 megawatts, or (ii) the purchase by a public utility of energy, capacity, and environmental attributes from solar facilities described in clause (i) owned by persons other than a public utility is in the public interest, and the Commission shall so find if required to make a finding regarding whether such construction or purchase is in the public interest.

B. Prior to January 1, 2024, (i) the construction or purchase by a public utility of one or more solar or wind generation facilities located in the Commonwealth or off the Commonwealth's Atlantic shoreline, each having a rated capacity of less than one megawatt, including rooftop solar installations with a capacity of not less than 50 kilowatts, and having in the aggregate a rated capacity that does not exceed 500 megawatts, or (ii) the purchase by a public utility of energy, capacity, and environmental attributes from solar facilities described in clause (i) owned by persons other than a public utility is in the public interest, and the Commission shall so find if required to make a finding regarding whether such construction or purchase is in the public interest.

C. The aggregate cap of 5,000 megawatts of rated capacity described in clause (i) of subsection A, the aggregate cap of 500 megawatts of rated capacity described in clause (i) of subsection B, and the aggregate cap of 200 megawatts of rated capacity described in subsection I are separate and independent from each other. The capacity of facilities in subsection B shall not be counted in determining the capacity of facilities in subsection A or I; the capacity of facilities in subsection A shall not be counted in determining the capacity of facilities in subsection B or I; and the capacity of facilities in subsection I shall not be counted in determining the capacity of facilities in subsection A or B.

D. Twenty-five percent of the solar generation capacity placed in service on or after July 1, 2018, located in the Commonwealth, and found to be in the public interest pursuant to subsection A or B shall be from the purchase by a public utility of energy, capacity, and environmental attributes from solar facilities owned by persons other than a public utility. The remainder shall be construction or purchase by a public utility of one or more solar generation facilities located in the Commonwealth. All of the solar generation capacity located in the Commonwealth and found to be in the public interest pursuant to subsection A or B shall be subject to competitive procurement, provided that a public utility may select solar generation capacity without regard to whether such selection satisfies price criteria if the selection of the solar generating capacity materially advances non-price criteria, including favoring geographic distribution of generating capacity, areas of higher employment, or regional economic development, if such non-price solar generating capacity selected does not exceed 25 percent of the utility's solar generating capacity.

E. Construction, purchasing, or leasing activities for a test or demonstration project for a new 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.

F. Prior to January 1, 2035, (i) the construction by a public utility of one or more energy storage facilities located in the Commonwealth, having in the aggregate a rated capacity that does not exceed 2,700 megawatts, or (ii) the purchase by a public utility of energy storage facilities described in clause (i) owned by persons other than a public utility or the capacity from such facilities is in the public interest, and the Commission shall so find if required to make a finding regarding whether such construction or purchase is in the public interest.

G. At least 35 percent of the energy storage capacity placed in service on or after July 1, 2020, located in the Commonwealth and found to be in the public interest pursuant to subsection F shall be from the purchase by a public utility of energy storage facilities owned by persons other than a public utility or the capacity from such facilities. All of the energy storage facilities located in the Commonwealth and found to be in the public interest pursuant to subsection F shall be subject to competitive procurement, provided that a public utility may select energy storage facilities without regard to whether such selection satisfies price criteria if the selection of the energy storage facilities materially advances non-price criteria, including favoring geographic distribution of generating facilities, areas of higher employment, or regional economic development, if such energy storage facilities selected for the advancement of non-price criteria do not exceed 25 percent of the utility's energy storage capacity.

H. A utility may elect to petition the Commission, outside of a triennial or biennial review proceeding conducted pursuant to § 56-585.1 , at any time for a prudency determination with respect to the construction or purchase by the utility of one or more solar or wind generation facilities located in the Commonwealth or off the Commonwealth's Atlantic Shoreline or the purchase by the utility of energy, capacity, and environmental attributes from solar or wind facilities owned by persons other than the utility. The Commission's final order regarding any such petition shall be entered by the Commission not more than three months after the date of the filing of such petition.

I. Prior to January 1, 2024, (i) the construction or purchase by a public utility of one or more solar or wind generation facilities located on a previously developed project site in the Commonwealth having in the aggregate a rated capacity that does not exceed 200 megawatts or (ii) the purchase by a public utility of energy, capacity, and environmental attributes from solar facilities described in clause (i) owned by persons other than a public utility, is in the public interest.

2018, c. 296 ; 2020, cc. 1190 , 1193 , 1194 , 1225 ; 2023, cc. 757 , 775 .
Va. Code Ann. § 56-577.1 — Virginia Code / Title 56 / Chapter 23 / Section 56-577.1
Electric utilities; retail competition; pilot program
Status: in_force

A. The Commission shall conduct a pilot program under which two or more nonresidential customers that, as of February 25, 2019, had filed applications seeking to aggregate their load pursuant to subdivision A 4 of § 56-577 within the service territory of a Phase II Utility, as that term is defined in subsection A of § 56-585.1 , shall be permitted to purchase electric energy from any supplier of electric energy licensed to sell electric energy within the Commonwealth, subject to the following terms, conditions, and restrictions:

1. A pilot program shall be conducted within the certified service territory of the Phase II Utility in which such nonresidential customers are located.

2. The aggregated load participating in the pilot program shall not exceed 200 megawatts.

3. All customers participating in the pilot program shall be subject in all respects to the provisions of subdivision A 3 of § 56-577 , with participation in this pilot program being deemed to satisfy subdivision A 4 of § 56-577 and with the load set forth in each application being treated as a single, individual customer for purposes of said subdivision, and shall submit an annual report to the Commission by March 31 each year to demonstrate that, for the preceding calendar year, such load continued to meet the demand limitations of subdivision A 3 of § 56-577 .

B. The Commission shall review the pilot program established pursuant to subsection A in 2022.

2020, c. 796 .
Va. Code Ann. § 56-484 — Virginia Code / Title 56 / Chapter 15 / Article 3 / Section 56-484
Foreign companies to obtain license
Status: in_force

Every telephone or telegraph company, not incorporated by the laws of this Commonwealth, shall, as a condition precedent to the enjoyment of any right or privilege granted by this chapter, first obtain from the Commission a license to do business in this Commonwealth, and pay the fees and taxes imposed by law for such license.

Code 1919, § 4036.
Va. Code Ann. § 56-16.2 — Virginia Code / Title 56 / Chapter 1 / Article 4 / Section 56-16.2
Public utility lines crossing railroads
Status: in_force

A. As used in this section:

"Municipality" means a city, county, town, authority, or other political subdivision of the Commonwealth.

"Public utility line" means any line, wire, pipe, or conduit that is used in connection with the provision of water, sewer, or telecommunications service by a municipality, and includes any poles and other appurtenant fixtures and structures that are necessary and appropriate for the operation and support of such line, wire, pipe, or conduit.

B. If a municipality desires to cross the works of a railroad company with a public utility line and the municipality and railroad company cannot agree on the manner of the crossing or the compensation to be paid or the damages, if any, occasioned by such crossing, then either party, after complying with the provisions of §§ 56-17 and 56-18 , insofar as they are applicable, may apply to the Commission within 30 days after the submission of the plans and specifications required in § 56-18 to inquire into the necessity for such crossing, the propriety of the proposed location, all matters pertaining to its construction and operation, and a fee for such crossing and damages, if any, to be paid to the railroad company.

C. Every such application shall, in addition to the plans and specifications required in § 56-18 , set forth (i) the means the applicant proposes to employ to protect persons and property on the premises of the railroad; (ii) standard railroad liability protection insurance to safeguard the railroad from damage or destruction of persons or property resulting from such crossing, including a provision to save the railroad harmless from claims arising as a result of such crossing; (iii) the conditions under which usage of the crossing will terminate and all interests revert to the railroad; and (iv) the means which the applicant proposes to employ to prevent interference with the unlimited use of the property by the railroad including, but without limitation, the communication and transportation system on the property proposed to be crossed. The Commission may, at its discretion, require the applicant to provide a bond or insurance conditioned to save the railroad harmless from claims arising as a result of such crossing. The Commission may, as provided in § 56-19 , employ experts to advise it with reference to such application.

D. If the Commission grants such application in whole or in part, the order of the Commission shall require the railroad to grant to the municipality a license for such crossing upon compliance with the terms of the order, and shall fix a fee for the crossing and determine the damages, if any. The amount of the fee for the crossing fixed by the Commission shall not exceed the actual costs reasonably expected to be incurred by the railroad company as a result of the crossing and the periodic inspection of such works but shall take into consideration the systemwide administrative and other costs of the railroad to implement utility crossing agreements.

E. Construction shall not begin until permitted under an order provided for in subsection D unless the parties agree thereto; however, the Commission may allow construction to proceed pending the determination of the fee and damages, if any.

2006, c. 383 .
Va. Code Ann. § 56-390 — Virginia Code / Title 56 / Chapter 13 / Article 5 / Section 56-390
Repealed
Status: repealed

Repealed by Acts 1970, c. 731.
Va. Code Ann. § 56-452 — Virginia Code / Title 56 / Chapter 14 / Section 56-452
Repealed
Status: repealed

Repealed by Acts 1970, c. 243.
Va. Code Ann. § 56-585.3 — Virginia Code / Title 56 / Chapter 23 / Section 56-585.3
Regulation of cooperative rates after rate caps
Status: in_force

A. After the expiration or termination of capped rates, the rates, terms and conditions of distribution electric cooperatives subject to Article 1 (§ 56-231.15 et seq.) of Chapter 9.1 shall be regulated in accordance with the provisions of Chapters 9.1 (§ 56-231.15 et seq.) and 10 (§ 56-232 et seq.), as modified by the following provisions:

1. Except for energy related cost (fuel cost), the Commission shall not require any cooperative to adjust, modify, or revise its rates, by means of riders or otherwise, to reflect changes in wholesale power cost which occurred during the capped rate period, other than in a general rate proceeding;

2. Each cooperative may, without Commission approval or the requirement of any filing other than as provided in this subdivision, upon an affirmative resolution of its board of directors, increase or decrease all classes of its rates for distribution services at any time, provided, however, that such adjustments will not effect a cumulative net increase or decrease in excess of five percent in such rates in any three-year period. Such adjustments will not affect or be limited by any existing fuel or wholesale power cost adjustment provisions. The cooperative will promptly file any such revised rates with the Commission for informational purposes;

3. Each cooperative may, without Commission approval, upon an affirmative resolution of its board of directors, make any adjustment to its terms and conditions that does not affect the cooperative's revenues from the distribution or supply of electric energy. In addition, a cooperative may make such adjustments to any pass-through of third-party service charges and fees, and to any fees, charges and deposits set out in Schedule F of such cooperative's Terms and Conditions filed as of January 1, 2007. The cooperative will promptly file any such amended terms and conditions with the Commission for informational purposes;

4. Each cooperative may, without Commission approval or the requirement of any filing other than as provided in this subdivision, upon an affirmative resolution of its board of directors, make any adjustment to its rates reasonably calculated to collect any or all of the fixed costs of owning and operating its electric distribution system, including without limitation, such costs as are identified as customer-related costs in a cost of service study, through a new or modified fixed monthly charge, rather than through volumetric charges associated with the use of electric energy or demand, or to rebalance among any of the fixed monthly charge, distribution demand, and distribution energy; however, such adjustments shall be revenue neutral based on the cooperative's determination of the proper intra-class allocation of the revenues produced by its then current rates. If a rate class contains a supply demand charge, the cooperative may rebalance its rate for electricity supply service pursuant to this subdivision. The cooperative may elect, but is not required, to implement such adjustments through incremental changes over the course of up to three years. The cooperative shall file promptly revised tariffs reflecting any such adjustments with the Commission for informational purposes;

5. A cooperative may, at any time after the expiration or termination of capped rates, petition the Commission for approval of one or more rate adjustment clauses for the timely and current recovery from customers of the costs described in subdivisions A 5 b and e of § 56-585.1 ;

6. A cooperative that is not a current member of a utility aggregation cooperative may at any time petition the Commission for approval of one or more rate adjustment clauses for the timely and current recovery of cost from customers of (i) one or more generation facilities, (ii) one or more major unit modifications of generation facilities, or (iii) one or more pumped hydroelectricity generation and storage facilities. A cooperative seeking a rate adjustment clause pursuant to this subdivision shall have the right, after notice and the opportunity for a hearing, to recover the costs of a facility described in clauses (i), (ii), or (iii) in a rate adjustment clause including construction work in progress and allowance for funds during construction, planning, and development costs of infrastructure associated therewith. The costs of the facility other than projected construction work in progress and allowance for funds used during construction shall not be recovered prior to the date that the facility either (a) begins commercial operation or (b) comes under the ownership of the cooperative. For the purposes of this subdivision, the cooperative's cost of capital shall be recoverable in such a rate adjustment clause and shall be set as either the cooperative's long-term cost of debt or most recent rate of return authorized by the Commission in a rate proceeding. In any proceeding conducted pursuant to this subdivision, the Commission shall consider that all costs expended and revenues recovered arising out of the procurement of generation resources pursuant to this subdivision will inure to the benefit of the general membership of the cooperative. Nothing in this subdivision shall relieve a cooperative from any requirement to obtain a certificate of public convenience and necessity for purposes of constructing generation in the Commonwealth. The Commission's final order regarding any petition filed pursuant to this subdivision shall be entered not more than nine months 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. Any petition filed pursuant to this subdivision shall be considered by the Commission on a stand-alone basis without regard to the other costs, revenues, investments, or earnings of the cooperative. Any costs incurred by a cooperative prior to the filing of such petition, or during the consideration thereof by the Commission, that are proposed for recovery in such petition, shall be deferred on the books and records of the cooperative until the Commission's final order in the matter, or until the implementation of any applicable approved rate adjustment clause, whichever is later;

7. A cooperative may adopt any other cooperative's voluntary rate, voluntary program (including a pilot program), or voluntary tariff, and cost recovery therefor, by submitting the same to the Commission for administrative approval. The staff of the Commission shall have the authority to approve such administrative filing notwithstanding any other provision of law; and

8. A cooperative may, without approval of the Commission or the requirement of any filing other than as provided in this subsection, upon an affirmative resolution of its board of directors, approve any voluntary tariff, and cost recovery therefor, and shall promptly file any such tariff with the Commission for informational purposes.

B. None of the adjustments described in subdivisions A 2 through A 5 will apply to the rates paid by any customer that takes service by means of dedicated distribution facilities and had noncoincident peak demand in excess of 90 megawatts in calendar year 2006.

C. Nothing in this section shall be deemed to grant to a cooperative any authority to amend or adjust any terms and conditions of service or agreements regarding pole attachments or the use of the cooperative's poles or conduits.

2007, cc. 888 , 933 ; 2009, cc. 401 , 824 ; 2019, cc. 625 , 742 , 763 ; 2022, cc. 363 , 364 .
Va. Code Ann. § 56-265.11:1 — Virginia Code / Title 56 / Chapter 10.2 / Section 56-265.11:1
Notification to energy utilities
Status: in_force

Each person operating a sewerage system which includes one or more sewage treatment plants shall notify in writing, the Commission, the Director of the Department of Environmental Quality and each electric or natural gas utility supplying or distributing energy to such system that such system includes a sewage treatment plant.

2000, c. 183 .
Va. Code Ann. § 56-245.3 — Virginia Code / Title 56 / Chapter 10 / Article 2.1 / Section 56-245.3
Commission to promulgate regulations and standards
Status: in_force

A. Notwithstanding any law to the contrary, the Commission shall promulgate regulations and standards under which any owner, operator, or manager of an apartment house, office building, shopping center, or campground, which is not individually metered for electricity or gas for each dwelling unit, nonresidential rental unit, or campsite may install submetering equipment or energy allocation equipment for the purpose of fairly allocating (a) the cost of electrical or gas consumption for each dwelling unit, nonresidential rental unit, or campsite and (b) electrical or gas demand and customer charges made by the utility. In addition to other appropriate safeguards for the tenant, the regulations shall require (i) that an apartment house, office building, shopping center, or campground owner shall not impose on the tenant any charges, over and above the cost per kilowatt hour, cubic foot or therm, plus demand and customer charges, where applicable, which are charged by the utility company to the owner, including any sales, local utility, or other taxes, if any, except that additional service charges permitted by § 55.1-1212 or 55.1-1404 , as applicable, may be collected to cover administrative costs and billing, and (ii) that the apartment house, office building, shopping center, or campground owner shall maintain adequate records regarding submetering and energy allocation equipment and shall make such records available for inspection by the Commission during reasonable business hours. The provisions of this section shall not restrict the right of the owner, operator or manager to recover in periodic lease payments the tenant's fair share of electricity or gas costs attributable to owner-paid areas and costs incurred by the owner, operator or manager in establishing and maintaining the submetering or energy allocation equipment.

B. Only for purposes of Commission enforcement of the regulations adopted under this section, the owners, operators, or managers of apartment houses, office buildings, shopping centers, or campgrounds included within the purview of this article shall be treated as public service corporations under §§ 56-5 , 56-6 and 56-7 . All submetering equipment shall be subject to the same regulations and standards established by the Commission for accuracy, testing, and record keeping of meters installed by electric or gas utilities and shall be subject to the meter requirements of § 56-245.1 . All energy allocation equipment shall be subject to regulations and standards established by the Commission to ensure that such systems result in a reasonable determination of energy use and the resulting costs for each dwelling unit, nonresidential rental unit, or campsite. Violations of Commission regulations and orders issued under this section shall be subject to the penalty set forth in § 12.1-33 .

C. In implementing this section, no apartment house, office building, shopping center, or campground shall be considered a public utility or public service corporation engaged in the business of distributing or reselling electricity or gas except as provided in subsection B. The apartment house, office building, shopping center, or campground may use submetering or energy allocation equipment solely to allocate the costs of electric or gas service fairly among the tenants using the apartment house, office building, shopping center, or campground.

D. For the purposes of rules promulgated pursuant to this section, billing requirements and all other rules related to submetering or energy allocation equipment use by tenants of an apartment house, office building, shopping center, or campground shall apply to residential and nonresidential unit owners.

1978, c. 392; 1979, c. 313; 1980, c. 741; 1986, c. 11; 1988, c. 231; 1989, c. 188; 1991, c. 573; 1992, c. 766; 2003, c. 355 ; 2012, c. 338 ; 2024, c. 557 .
Va. Code Ann. § 56-575.1 — Virginia Code / Title 56 / Chapter 22.1 / Section 56-575.1
Definitions
Status: in_force

As used in this chapter, unless the context requires a different meaning:

"Affected jurisdiction" means any county, city or town in which all or a portion of a qualifying project is located.

"Appropriating body" means the body responsible for appropriating or authorizing funding to pay for a qualifying project.

"Commission" means the State Corporation Commission.

"Comprehensive agreement" means the comprehensive agreement between the private entity and the responsible public entity required by § 56-575.9 .

"Develop" or "development" means to plan, design, develop, finance, lease, acquire, install, construct, or expand.

"Interim agreement" means an agreement between a private entity and a responsible public entity that provides for phasing of the development or operation, or both, of a qualifying project. Such phases may include, but are not limited to, design, planning, engineering, environmental analysis and mitigation, financial and revenue analysis, or any other phase of the project that constitutes activity on any part of the qualifying project.

"Lease payment" means any form of payment, including a land lease, by a public entity to the private entity for the use of a qualifying project.

"Material default" means any default by the private entity in the performance of its duties under subsection E of § 56-575.8 that jeopardizes adequate service to the public from a qualifying project.

"Operate" means to finance, maintain, improve, equip, modify, repair, or operate.

"Private entity" means any natural person, corporation, general partnership, limited liability company, limited partnership, joint venture, business trust, public benefit corporation, non-profit entity, or other business entity.

"Public entity" means the Commonwealth and any agency or authority thereof, any county, city or town and any other political subdivision of the Commonwealth, any public body politic and corporate, or any regional entity that serves a public purpose.

"Qualifying project" means (i) any education facility, including, but not limited to a school building, any functionally related and subordinate facility and land to a school building (including any stadium or other facility primarily used for school events), and any depreciable property provided for use in a school facility that is operated as part of the public school system or as an institution of higher education; (ii) any building or facility that meets a public purpose and is developed or operated by or for any public entity; (iii) any improvements, together with equipment, necessary to enhance public safety and security of buildings to be principally used by a public entity; (iv) utility and telecommunications and other communications infrastructure; (v) a recreational facility; (vi) technology infrastructure, services, and applications, including, but not limited to, telecommunications, automated data processing, word processing and management information systems, and related information, equipment, goods and services; (vii) any services designed to increase the productivity or efficiency of the responsible public entity through the use of technology or other means, (viii) any technology, equipment, or infrastructure designed to deploy wireless broadband services to schools, businesses, or residential areas; (ix) any improvements necessary or desirable to any unimproved locally- or state-owned real estate; or (x) any solid waste management facility as defined in § 10.1-1400 that produces electric energy derived from solid waste.

"Responsible public entity" means a public entity that has the power to develop or operate the applicable qualifying project.

"Revenues" means all revenues, income, earnings, user fees, lease payments, or other service payments arising out of or in connection with supporting the development or operation of a qualifying project, including without limitation, money received as grants or otherwise from the United States of America, from any public entity, or from any agency or instrumentality of the foregoing in aid of such facility.

"Service contract" means a contract entered into between a public entity and the private entity pursuant to § 56-575.5 .

"Service payments" means payments to the private entity of a qualifying project pursuant to a service contract.

"State" means the Commonwealth of Virginia.

"User fees" mean the rates, fees or other charges imposed by the private entity of a qualifying project for use of all or a portion of such qualifying project pursuant to the comprehensive agreement pursuant to § 56-575.9 .

2002, c. 571 ; 2003, c. 1034 ; 2005, cc. 618 , 865 ; 2007, cc. 649 , 764 ; 2008, cc. 273 , 731 ; 2009, cc. 754 , 762 .
Va. Code Ann. § 56-428 — Virginia Code / Title 56 / Chapter 13 / Article 8 / Section 56-428
Railroads liable for damage from fires set out by their engines or trains
Status: in_force

Whenever any person sustains damage from fire occasioned by sparks or coals dropped or thrown from the engine or train of any railroad company, such company shall be liable for the damage so sustained, whether such fire originated on the company's right-of-way or not.

Code 1919, § 3992; 1996, cc. 114 , 157 .
Va. Code Ann. § 56-86 — Virginia Code / Title 56 / Chapter 4 / Section 56-86
Appeal from decisions of Commission under chapter
Status: in_force

Any public service company or affiliated interest or any other interested corporation, partnership, association or person, or the Commonwealth, deeming any decision or order of the Commission, rendered or entered under the provisions of this chapter, and being final in its general character with respect to any such company, interest, corporation, partnership, association, person, or the Commonwealth, to be in any respect or manner improper, unjust or unreasonable, may appeal the same to the Supreme Court in the same manner and by the same procedure as provided by law for review of any other decision or order of the Commission.

1934, p. 746; 1938, p. 23; Michie Code 1942, § 3774j.
Va. Code Ann. § 56-129 — Virginia Code / Title 56 / Chapter 6 / Article 5 / Section 56-129
Repealed
Status: repealed

Repealed by Acts 1996, cc. 114 and 157 .
Va. Code Ann. § 56-257.1 — Virginia Code / Title 56 / Chapter 10 / Article 5 / Section 56-257.1
Means of locating nonmetallic underground conduits
Status: in_force

Any plastic or other nonmetallic pressurized conduit installed underground on and after July 1, 1976, shall have affixed thereto a wire conductive of electricity or some other means of locating the conduit while it is underground.

1976, c. 556.
Va. Code Ann. § 56-248 — Virginia Code / Title 56 / Chapter 10 / Article 3 / Section 56-248
Commission to prescribe standard units of products or service
Status: in_force

The Commission shall ascertain and prescribe for each kind of public utility suitable standard commercial units of products or service. This section shall not apply to telephone companies.

Code 1919, § 4070; 2011, cc. 738 , 740 .
Va. Code Ann. § 56-582 — Virginia Code / Title 56 / Chapter 23 / Section 56-582
Rate caps
Status: in_force

A. The Commission shall establish capped rates, effective January 1, 2001, for each service territory of every incumbent utility as follows:

1. Capped rates shall be established for customers purchasing bundled electric transmission, distribution and generation services from an incumbent electric utility.

2. Capped rates for electric generation services, only, shall also be established for the purpose of effecting customer choice for those retail customers authorized under this chapter to purchase generation services from a supplier other than the incumbent utility during this period.

3. The capped rates established under this section shall be the rates in effect for each incumbent utility as of the effective date of this chapter, or rates subsequently placed into effect pursuant to a rate application filed by an incumbent electric utility with the Commission prior to January 1, 2001, and subsequently approved by the Commission, and made by an incumbent electric utility that is not currently bound by a rate case settlement adopted by the Commission that extends in its application beyond January 1, 2002. If such rate application is filed, the rates proposed therein shall go into effect on January 1, 2001, but such rates shall be interim in nature and subject to refund until such time as the Commission has completed its investigation of such application. Any amount of the rates found excessive by the Commission shall be subject to refund with interest, as may be ordered by the Commission. The Commission shall act upon such applications prior to January 1, 2002. Such rate application and the Commission's approval shall give due consideration, on a forward-looking basis, to the justness and reasonableness of rates to be effective for a period of time ending as late as July 1, 2007. The capped rates established under this section, which include rates, tariffs, electric service contracts, and rate programs (including experimental rates, regardless of whether they otherwise would expire), shall be such rates, tariffs, contracts, and programs of each incumbent electric utility, provided that experimental rates and rate programs may be closed to new customers upon application to the Commission. Such capped rates shall also include rates for new services where, subsequent to January 1, 2001, rate applications for any such rates are filed by incumbent electric utilities with the Commission and are thereafter approved by the Commission. In establishing such rates for new services, the Commission may use any rate method that promotes the public interest and that is fairly compensatory to any utilities requesting such rates.

B. The Commission may adjust such capped rates in connection with the following: (i) utilities' recovery of fuel and purchased power costs pursuant to § 56-249.6 , and, if applicable, in accordance with the terms of any Commission order approving the divestiture of generation assets pursuant to § 56-590 , (ii) any changes in the taxation by the Commonwealth of incumbent electric utility revenues, (iii) any financial distress of the utility beyond its control, (iv) with respect to cooperatives that were not members of a power supply cooperative on January 1, 1999, and as long as they do not become members, their cost of purchased wholesale power and discounts from capped rates to match the cost of providing distribution services, (v) with respect to cooperatives that were members of a power supply cooperative on January 1, 1999, their recovery of fuel costs, through the wholesale power cost adjustment clauses of their tariffs pursuant to § 56-231.33 , and (vi) with respect to incumbent electric utilities that were not, as of the effective date of this chapter, bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002, the Commission shall adjust such utilities' capped rates, not more than once in any 12-month period, for the timely recovery of their incremental costs for transmission or distribution system reliability and compliance with state or federal environmental laws or regulations to the extent such costs are prudently incurred on and after July 1, 2004. Any adjustments pursuant to § 56-249.6 and clause (i) of this subsection by an incumbent electric utility that transferred all of its generation assets to an affiliate with the approval of the Commission pursuant to § 56-590 prior to January 1, 2002, shall be effective only on and after July 1, 2007. Notwithstanding the provisions of § 56-249.6 , the Commission may authorize tariffs that include incentives designed to encourage an incumbent electric utility to reduce its fuel costs by permitting retention of a portion of cost savings resulting from fuel cost reductions or by other methods determined by the Commission to be fair and reasonable to the utility and its customers.

C. A utility may petition the Commission to terminate the capped rates to all customers any time after January 1, 2004, and such capped rates may be terminated upon the Commission finding of an effectively competitive market for generation services within the service territory of that utility. If its capped rates, as established and adjusted from time to time pursuant to subsections A and B, are continued after January 1, 2004, an incumbent electric utility that is not, as of the effective date of this chapter, bound by a rate case settlement adopted by the Commission that extends in its application beyond January 1, 2002, may petition the Commission, during the period January 1, 2004, through June 30, 2007, for approval of a one-time change in its rates, and if the capped rates are continued after July 1, 2007, such incumbent electric utility may at any time after July 1, 2007, petition the Commission for approval of a one-time change in its rates. Any change in rates pursuant to this subsection by an incumbent electric utility that divested its generation assets with approval of the Commission pursuant to § 56-590 prior to January 1, 2002, shall be in accordance with the terms of any Commission order approving such divestiture. Any petition for changes to capped rates filed pursuant to this subsection shall be governed by the provisions of Chapter 10 (§ 56-232 et seq.) of this title.

D. Until the expiration or termination of capped rates as provided in this section, the incumbent electric utility, consistent with the functional separation plan implemented under § 56-590 , shall make electric service available at capped rates established under this section to any customer in the incumbent electric utility's service territory, including any customer that, until the expiration or termination of capped rates, requests such service after a period of utilizing service from another supplier.

E. During the period when capped rates are in effect for an incumbent electric utility, such utility may file with the Commission a plan describing the method used by such utility to assure full funding of its nuclear decommissioning obligation and specifying the amount of the revenues collected under either the capped rates, as provided in this section, or the wires charges, as provided in former § 56-583 , that are dedicated to funding such nuclear decommissioning obligation under the plan. The Commission shall approve the plan upon a finding that the plan is not contrary to the public interest.

F. The capped rates established pursuant to this section shall expire on December 31, 2008, unless sooner terminated by the Commission pursuant to the provisions of subsection C; however, rates after the expiration or termination of capped rates shall equal capped rates until such rates are changed pursuant to other provisions of this title.

1999, c. 411 ; 2000, cc. 942 , 991 ; 2001, c. 748 ; 2004, c. 827 ; 2007, cc. 888 , 933 ; 2008, c. 883 .
Va. Code Ann. § 56-231.26 — Virginia Code / Title 56 / Chapter 9.1 / Article 1 / Section 56-231.26
Covenants in connection with obligations
Status: in_force

In connection with the issuance of any obligations a cooperative may make covenants or agreements and do any and all acts or things that a corporation can make or do under the laws of this Commonwealth.

1999, c. 874 .
Va. Code Ann. § 56-543 — Virginia Code / Title 56 / Chapter 20 / Section 56-543
Powers and duties of roadway operator
Status: in_force

A. The operator shall have all power allowed by law generally to persons having the same form of organization as the operator, including, without limitation, the authority to operate the roadway and charge tolls for the use thereof, and may pledge any revenue net of operational expenses realized from tolls charged for the use of the roadway in order to secure repayment of any obligations incurred for the construction, enlargement or operation of such roadway. Any financing of the acquisition, construction, enlargement, or operation of the roadway may be in such amounts and upon such terms and conditions as may be deemed necessary or appropriate by the operator to provide for the acquisition, construction, enlargement, and operation of the roadway, issuance costs, other financing obligations, and reasonable reserves. The Commonwealth shall not obligate its full faith and credit on any financing of the operator. Assumption of operation of the project shall not obligate the Commonwealth to pay any obligation of the operator whether secured or otherwise, from sources other than toll revenue. Subject to applicable permit requirements, the operator shall have the authority to cross any canal or navigable watercourse so long as the crossing does not unreasonably interfere with navigation and use of the waterway. In operating the roadway, the operator may:

1. Classify traffic according to reasonable categories for assessment of tolls; and

2. With the consent of the Department, make and enforce reasonable regulations, including regulations:

a. Which set maximum and minimum speeds that shall conform to Department and state practices;

b. Which exclude undesirable vehicles or cargoes or materials from the use of the roadway; or

c. Which establish commuter lanes for use during all or any part of a day and limit the use of such lanes to certain traffic.

3. The enumeration of powers in this subsection shall not limit the power of the operator to do anything it deems necessary and appropriate in the operation of the roadway, provided that the practice is reasonable and nondiscriminatory. The powers granted to the operator in this subsection shall not be deemed to limit the authority of the Commission to regulate the operator under this title.

B. The operator shall have the following duties:

1. It shall file and maintain at all times with the Commission an accurate schedule of rates charged to the public for use of all or any portion of the roadway and it shall also file and maintain a statement that such rates will apply uniformly to all users within any such reasonable classification as the operator may elect to implement. These rates shall be neither applied nor collected in a discriminatory fashion, and free vehicular passage shall be permitted to those persons referred to in subsection A of § 33.2-613 .

2. It shall construct and maintain the roadway for anticipated use according to appropriate standards of the Department for public highways operated and maintained by the Department, and enlarge or expand the road when unsatisfied demand for use of the roadway makes it economically feasible to do so. The operator shall agree with the Department for inspection of construction work by the Department at appropriate times during any construction or enlargement. In addition, it shall cooperate fully with the Department in establishing any interconnection with the roadway that the Department may make.

3. It shall contract with the Commonwealth for enforcement of the traffic and public safety laws by state authorities, and may similarly contract with appropriate local authorities for those portions of the roadway within the local jurisdiction.

1988, c. 649; 1991, c. 272; 1993, c. 732.
Va. Code Ann. § 56-16.3 — Virginia Code / Title 56 / Chapter 1 / Article 4 / Section 56-16.3
Fiber optic broadband lines crossing railroads
Status: in_force

A. For the purposes of this section:

"Actual flagging expenses" means expenses directly attributable to the cost of maintaining flaggers at the point of the crossing during the period of time construction is actually occurring. "Actual flagging expenses" shall be considered pass-through expenses and shall not exceed the expense incurred by the railroad company.

"Broadband service provider" means (i) an entity that provides broadband service through the utilization of a fiber optic broadband line, coaxial cable, or other wireline system or (ii) a Phase I or Phase II Utility, as those terms are defined in subdivision A 1 of § 56-585.1 , or a cooperative, as defined in § 56-231.15 , that provides middle-mile infrastructure to Internet service providers.

"Direct expenses" includes (i) the cost of inspecting and monitoring the crossing site; (ii) administrative and engineering costs for review of specifications and for entering a crossing on the railroad's books, maps, and property records, and other reasonable administrative and engineering costs incurred as a result of the crossing; (iii) document and preparation fees associated with a crossing and any engineering specifications related to the crossing; and (iv) actual flagging expenses associated with the crossing.

"Fiber optic broadband line" means (i) a fiber optic cable consisting of one or more thin flexible fibers with a glass core through which light signals can transmit data as pulses, a coaxial cable, or other wireline system of technology used for broadband distribution or (ii) the middle-mile infrastructure to Internet service providers.

"License fee" means the fee to be paid by the broadband service provider to the railroad company for the crossing, including all occupancy or real property rights.

"Railroad company" includes any company, trustee, or other person that owns, leases, or operates a railroad or owns or leases the land upon which a railroad is operated, and any company, trustee, or other person to which a railroad company has granted rights to collect or retain all or a portion of any revenue stream owed by a third party for use of or access to such railroad company's facilities or property.

B. If a broadband service provider deems it necessary in the construction of its systems to cross the works of a railroad company, including its tracks, bridges, facilities, and all railroad company rights of way or easements, then the broadband service provider shall submit an application for such crossing to the railroad company.

C. The procedure for a crossing shall be as follows:

1. The broadband service provider's application shall include (i) the license fee described in subsection G; (ii) engineering design plans, construction plans, bore plans, fraction mitigation plans, dewatering plans, rigging and lifting plans, and any other pertinent plans deemed necessary and prepared by a registered professional engineer; (iii) the location of the crossing, including whether it is located in a public right-of-way; (iv) the proposed date of commencement of work; (v) the anticipated duration of the work in the crossing; (vi) the areas in which the project personnel will work; and (vii) the contact information of the broadband service provider's point of contact. Notice shall also be provided to the electric utility in whose certificated service territory the crossing is proposed to be located.

2. Upon receipt of the broadband service provider's crossing application, the railroad company shall acknowledge receipt of such application.

3. The railroad company shall review the application and may request additional information or clarification from the broadband service provider within 15 days from receipt of the application. If additional information or clarification is requested, the broadband service provider shall respond within 10 days from the receipt of the request.

4. The railroad company shall approve the broadband service provider's crossing application within 35 days after the application is received unless the railroad company petitions the Commission pursuant to subsection H.

D. Any proposed crossing shall be (i) located, constructed, and operated so as not to impair, impede, or obstruct, in any material degree, the works and operations of the railroad to be crossed; (ii) supported by permanent and proper structures and fixtures; and (iii) controlled by customary and approved appliances, methods, and regulations to prevent damage to the works of the railroad and ensure the safety of its passengers.

E. The railroad company and the broadband service provider shall coordinate to schedule the crossing date, which shall be within 30 days of the approval of the crossing application, or such later date as indicated in the application or mutually agreed upon.

F. The broadband service provider shall be responsible for all aspects of the implementation of the physical crossing, including the construction and installation of the fiber optic broadband lines and all related equipment, conduit, wire masts, poles, towers, attachments, and infrastructure. The railroad company shall be responsible for flagging operations and other protective measures that it deems appropriate during the actual construction of fiber optic broadband lines. The broadband service provider shall be responsible for ensuring that the crossing is constructed and operated in accordance with accepted industry standards, including standards established by the National Electrical Safety Code, good utility practice, and industry-standard joint use processes of electric utilities.

G. The cost of any such crossing shall be borne by the broadband service provider. A broadband service provider that locates its fiber optic broadband line within a railroad right-of-way shall pay the railroad company for the right to make a crossing of the railroad company's works a license fee of $2,000 for each crossing unless (i) otherwise agreed to by the broadband service provider and the railroad company or (ii) the railroad company has petitioned the Commission as described in subsection H and the Commission has issued a subsequent order so stating. The broadband service provider shall reimburse the railroad company for direct expenses in addition to the license fee. Direct expenses shall not exceed $5,000 unless (a) otherwise agreed to by the broadband service provider and the railroad company or (b) the railroad company petitions the Commission for additional reimbursement and the Commission has issued a subsequent order so stating. The railroad company shall substantiate with documentation and other direct evidence of the direct expenses incurred to qualify for reimbursement. The establishment of a license fee cap by the Commonwealth is an exercise of its stated policy to promote the rapid deployment of broadband throughout the Commonwealth.

H. If the railroad company asserts that (i) the license fee is not adequate compensation for the proposed crossing, (ii) the proposed crossing will cause undue hardship on the railroad company, or (iii) the proposed crossing will create the imminent likelihood of danger to public health or safety, then the railroad company may petition the Commission for relief and provide simultaneous notice to the broadband service provider within 35 days from the date of the broadband service provider's application. The Commission may make any necessary findings of fact and determinations related to the adequacy of compensation, the existence of undue hardship on the railroad company, or the imminent likelihood of danger to public health or safety, as well as any relief to be granted, including any amount to which the railroad company is entitled in excess of the license fee prescribed in subsection G. If the railroad company asserts only that the license fee is not adequate compensation for the specified crossing, then the issue of compensation may be considered by the Commission after the commencement or completion of the work. The broadband service provider may petition the Commission for relief if the railroad company does not comply with this section or has otherwise wrongfully rejected or delayed its application. The Commission may, in its discretion, employ expert engineers, to be paid equally by both companies, to advise the Commission or a representative of the Commission in (a) examining the location, plans, specifications, and descriptions of appliances and the methods proposed to be employed; (b) hearing any objections and considering any modifications that the railroad company desires to offer; and (c) within such time as the Commission may determine, rejecting, approving, or modifying such plans and specifications. The Commission shall adjudicate any petition by the railroad company or broadband service provider and issue a final order within 90 days of the petition's initial filing. The Commission shall have sole jurisdiction to hear and resolve claims between railroad companies and broadband service providers concerning crossings and this section.

I. Notwithstanding the provisions of subsection G, if the broadband service provider submits an application to the railroad company to cross a section of track that has been legally abandoned pursuant to an order of a federal or state agency having jurisdiction over the track and is not being used for railroad service, then the license fee shall not exceed $1,000.

J. The Commonwealth shall grant a right-of-way to any broadband service provider seeking to use the right-of-way for broadband deployment to the extent that the Commonwealth owns any interest in any real property crossed by a railroad or manages any real property not owned by the Commonwealth that is crossed by a railroad.

K. Notwithstanding the provisions of subsection G, in no case shall a broadband service provider be required to pay a license fee for the right to make a crossing of the railroad company's works within a public right-of-way.

L. The broadband service provider shall maintain a commercial general liability insurance policy or railroad protective liability insurance policy that (i) does not exclude work within 50 feet of a railroad right-of-way, (ii) includes the railroad company as an additional insured, and (iii) remains in effect during the period of time construction is actually occurring.

M. The provisions of this section shall apply notwithstanding any contrary or other provision of law.

N. The provisions of this section shall be liberally construed and shall be construed in favor of broadband expansion.

2023, cc. 713 , 714 .
Va. Code Ann. § 56-604 — Virginia Code / Title 56 / Chapter 26 / Section 56-604
Filing of petition with Commission to establish or amend a SAVE plan; recovery of certain costs; procedure
Status: in_force

A. Notwithstanding any provisions of law to the contrary, a natural gas utility may file a SAVE plan as provided in this chapter. Such a plan shall provide for a timeline for completion of the proposed eligible infrastructure replacement projects, the estimated costs of the proposed eligible infrastructure projects, and a schedule for recovery of the related eligible infrastructure replacement costs through the SAVE rider, and demonstrate that the plan is prudent and reasonable. Such a plan may also include an enhanced leak detection and repair program, which shall include a description and an estimate of the associated enhanced leak detection and repair program costs. The Commission may approve such a plan after such notice and opportunity for hearing as the Commission may prescribe, subject to the provisions of this chapter.

B. The Commission shall approve or deny, within 180 days, a natural gas utility's initial application for a SAVE plan. A plan filed pursuant to this section shall not require the filing of rate case schedules. The Commission shall approve or deny, within 120 days, a natural gas utility's application to amend a previously approved plan. If the Commission denies such a plan or amendment, it shall set forth with specificity the reasons for such denial, and the utility shall have the right to refile, without prejudice, an amended plan or amendment within 60 days, and the Commission shall thereafter have 60 days to approve or deny the amended plan or amendment. The time period for Commission review provided for in this subsection shall not apply if the SAVE plan is filed in conjunction with a rate case using the cost of service methodology set forth in § 56-235.2 , or a performance-based regulation plan authorized by § 56-235.6 .

C. Any SAVE plan and any SAVE rider that is submitted to and approved by the Commission shall be allocated and charged in accordance with appropriate cost causation principles in order to avoid any undue cross-subsidization between rate classes.

D. No other revenue requirement or ratemaking issues may be examined in consideration of the application filed pursuant to the provisions of this chapter.

E. At the end of each 12-month period the SAVE rider is in effect, the natural gas utility shall reconcile the difference between the recognized eligible infrastructure replacement costs and the amounts recovered under the SAVE rider, and shall submit the reconciliation and a proposed SAVE rider adjustment to the Commission to recover or refund the difference, as appropriate, through an adjustment to the SAVE rider. The Commission shall approve or deny, within 90 days, a natural gas utility's proposed SAVE rider adjustment.

F. A natural gas utility that has implemented a SAVE rider pursuant to this chapter shall file revised rate schedules to reset the SAVE rider to zero, when new base rates and charges that incorporate eligible infrastructure replacement costs previously reflected in the currently effective SAVE rider become effective for the natural gas utility, following a Commission order establishing customer rates in a rate case using the cost of service methodology set forth in § 56-235.2 , or a performance-based regulation plan authorized by § 56-235.6 .

G. Costs recovered pursuant to this chapter shall be in addition to all other costs that the natural gas utility is permitted to recover, shall not be considered an offset to other Commission-approved costs of service or revenue requirements, and shall not be included in any computation relative to a performance-based regulation plan revenue-sharing mechanism. Further, if the Commission approves (i) an updated weighted average cost of capital for use in calculating the return on investment, (ii) the carrying costs on the over- or under-recovery of the eligible infrastructure replacement costs, (iii) the allowance for funds used during construction, or (iv) any combination thereof, such weighted average cost of capital shall be used only for the purpose of the eligible infrastructure replacement costs for the SAVE rider and shall not be used for any purpose in any other proceeding.

2010, cc. 142 , 514 ; 2022, cc. 728 , 759 .
Va. Code Ann. § 56-535 — Virginia Code / Title 56 / Chapter 20 / Section 56-535
Title
Status: in_force

This chapter may be cited as the "Virginia Highway Corporation Act of 1988."

1988, c. 649.