Va. Code Ann. § 56-585.5 — Virginia Code / Title 56 / Chapter 23 / Section 56-585.5
Generation of electricity from renewable and zero carbon sources
Status: in_force

A. As used in this section:

"Accelerated clean energy buyer" means a commercial or industrial customer of a Phase I or Phase II Utility, irrespective of generation supplier, with an aggregate load over 25 megawatts in the prior calendar year, that enters into arrangements pursuant to subsection G, as certified by the Commission.

"Aggregate load" means the combined electrical load associated with selected accounts of an accelerated clean energy buyer with the same legal entity name as, or in the names of affiliated entities that control, are controlled by, or are under common control of, such legal entity or are the names of affiliated entities under a common parent.

"Control" has the same meaning as provided in § 56-585.1:11 .

"Elementary or secondary" has the same meaning as provided in § 22.1-1 .

"Falling water" means hydroelectric resources, including run-of-river generation from a combined pumped-storage and run-of-river facility. "Falling water" does not include electricity generated from pumped-storage facilities.

"Low-income qualifying projects" means a project that provides a minimum of 50 percent of the respective electric output to low-income utility customers as that term is defined in § 56-576 .

"Phase I Utility" has the same meaning as provided in subdivision A 1 of § 56-585.1 .

"Phase II Utility" has the same meaning as provided in subdivision A 1 of § 56-585.1 .

"Previously developed project site" means any property, including related buffer areas, if any, that has been previously disturbed or developed for non-single-family residential, nonagricultural, or nonsilvicultural use, regardless of whether such property currently is being used for any purpose. "Previously developed project site" includes a brownfield as defined in § 10.1-1230 or any parcel that has been previously used (i) for a retail, commercial, or industrial purpose; (ii) as a parking lot; (iii) as the site of a parking lot canopy or structure; (iv) for mining, which is any lands affected by coal mining that took place before August 3, 1977, or any lands upon which extraction activities have been permitted by the Department of Energy under Title 45.2; (v) for quarrying; or (vi) as a landfill.

"Total electric energy" means total electric energy sold to retail customers in the Commonwealth service territory of a Phase I or Phase II Utility, other than accelerated clean energy buyers, by the incumbent electric utility or other retail supplier of electric energy in the previous calendar year, excluding an amount equivalent to the annual percentages of the electric energy that was supplied to such customer from nuclear generating plants located within the Commonwealth in the previous calendar year, provided such nuclear units were operating by July 1, 2020, or from any zero-carbon electric generating facilities not otherwise RPS eligible sources and placed into service in the Commonwealth after July 1, 2030.

"Zero-carbon electricity" means electricity generated by any generating unit that does not emit carbon dioxide as a by-product of combusting fuel to generate electricity.

B. 1. By December 31, 2024, except for any coal-fired electric generating units (i) jointly owned with a cooperative utility or (ii) owned and operated by a Phase II Utility located in the coalfield region of the Commonwealth that co-fires with biomass, any Phase I and Phase II Utility shall retire all generating units principally fueled by oil with a rated capacity in excess of 500 megawatts and all coal-fired electric generating units operating in the Commonwealth.

2. By December 31, 2045, except for biomass-fired electric generating units that do not co-fire with coal, each Phase I and II Utility shall retire all other electric generating units located in the Commonwealth that emit carbon as a by-product of combusting fuel to generate electricity.

3. A Phase I or Phase II Utility may petition the Commission for relief from the requirements of this subsection on the basis that the requirement would threaten the reliability or security of electric service to customers. The Commission shall consider in-state and regional transmission entity resources and shall evaluate the reliability of each proposed retirement on a case-by-case basis in ruling upon any such petition.

C. Each Phase I and Phase II Utility shall participate in a renewable energy portfolio standard program (RPS Program) that establishes annual goals for the sale of renewable energy to all retail customers in the utility's service territory, other than accelerated clean energy buyers pursuant to subsection G, regardless of whether such customers purchase electric supply service from the utility or from suppliers other than the utility. To comply with the RPS Program, each Phase I and Phase II Utility shall procure and retire Renewable Energy Certificates (RECs) originating from renewable energy portfolio standard eligible sources (RPS eligible sources). For purposes of complying with the RPS Program from 2021 to 2024, a Phase I and Phase II Utility may use RECs from any renewable energy facility, as defined in § 56-576 , provided that such facilities are located in the Commonwealth or are physically located within the PJM Interconnection, LLC (PJM) region. However, at no time during this period or thereafter may any Phase I or Phase II Utility use RECs from (i) renewable thermal energy, (ii) renewable thermal energy equivalent, or (iii) biomass-fired facilities that are outside the Commonwealth. From compliance year 2025 and all years after, each Phase I and Phase II Utility may only use RECs from RPS eligible sources for compliance with the RPS Program.

In order to qualify as RPS eligible sources, such sources must be (a) electric-generating resources that generate electric energy derived from solar or wind located in the Commonwealth or off the Commonwealth's Atlantic shoreline or in federal waters and interconnected directly into the Commonwealth or physically located within the PJM region; (b) falling water resources located in the Commonwealth or physically located within the PJM region that were in operation as of January 1, 2020, that are owned by a Phase I or Phase II Utility or for which a Phase I or Phase II Utility has entered into a contract prior to January 1, 2020, to purchase the energy, capacity, and renewable attributes of such falling water resources; (c) non-utility-owned resources from falling water that (1) are less than 65 megawatts, (2) began commercial operation after December 31, 1979, or (3) added incremental generation representing greater than 50 percent of the original nameplate capacity after December 31, 1979, provided that such resources are located in the Commonwealth or are physically located within the PJM region; (d) waste-to-energy or landfill gas-fired generating resources located in the Commonwealth and in operation as of January 1, 2020, provided that such resources do not use waste heat from fossil fuel combustion; (e) geothermal heating and cooling systems located in the Commonwealth; (f) geothermal electric generating resources located in the Commonwealth or physically located within the PJM region; or (g) biomass-fired facilities in operation in the Commonwealth and in operation as of January 1, 2023, that (1) supply no more than 10 percent of their annual net electrical generation to the electric grid or no more than 15 percent of their annual total useful energy to any entity other than the manufacturing facility to which the generating source is interconnected and are fueled by forest-product manufacturing residuals, including pulping liquor, bark, paper recycling residuals, biowastes, or biomass, as described in subdivisions A 1, 2, and 4 of § 10.1-1308.1 , provided that biomass as described in subdivision A 1 of § 10.1-1308.1 results from harvesting in accordance with best management practices for the sustainable harvesting of biomass developed and enforced by the State Forester pursuant to § 10.1-1105 , or (2) are owned by a Phase I or Phase II Utility, have less than 52 megawatts capacity, and are fueled by forest-product manufacturing residuals, biowastes, or biomass, as described in subdivisions A 1, 2, and 4 of § 10.1-1308.1 , provided that biomass as described in subdivision A 1 of § 10.1-1308.1 results from harvesting in accordance with best management practices for the sustainable harvesting of biomass developed and enforced by the State Forester pursuant to § 10.1-1105 . Regardless of any future maintenance, expansion, or refurbishment activities, the total amount of RECs that may be sold by any RPS eligible source using biomass in any year shall be no more than the number of megawatt hours of electricity produced by that facility in 2022; however, in no year may any RPS eligible source using biomass sell RECs in excess of the actual megawatt-hours of electricity generated by such facility that year. In order to comply with the RPS Program, each Phase I and Phase II Utility may use and retire the environmental attributes associated with any existing owned or contracted solar, wind, falling water, or biomass electric generating resources in operation, or proposed for operation, in the Commonwealth or solar, wind, or falling water resources physically located within the PJM region, with such resource qualifying as a Commonwealth-located resource for purposes of this subsection, as of January 1, 2020, provided that such renewable attributes are verified as RECs consistent with the PJM-EIS Generation Attribute Tracking System.

1. a. The RPS Program requirements shall be a percentage of the total electric energy sold in the previous calendar year and shall be implemented in accordance with the following schedule:

b. Beginning with the 2027 compliance year and thereafter, each Phase II Utility shall procure and retire RECs from geothermal heating and cooling systems located in the Commonwealth, as a percentage of the total number of RECs used for RPS program compliance, in the following amounts, at minimum: (i) 0.5 percent in 2027, (ii) 0.75 percent in 2028, and (iii) one percent in and after 2029. Beginning with the 2027 compliance year and thereafter, each Phase I Utility shall procure and retire RECs from geothermal heating and cooling systems located within its own service territory, as a percentage of the total number of RECs used for RPS program compliance, in the following amounts, at minimum: (a) 0.5 percent in 2027, (b) 0.75 percent in 2028, and (c) one percent in and after 2029.

2. A Phase II Utility shall meet the RPS Program requirements in any given compliance year with solar, wind, or anaerobic digestion resources of one megawatt or less located in the Commonwealth, measured as a percentage of the Phase II Utility's RPS Program requirements: (i) 4.5 percent for the 2026 through 2030 compliance years and (ii) five percent for the 2031 through 2045 compliance years. No more than 3,000 kilowatts of any such solar, wind, or anaerobic digestion resources may be located at any single location or at contiguous locations owned by the same entity or affiliated entities, and, to the extent that low-income qualifying projects are available, no less than 25 percent of such required percentage shall be composed of low-income qualifying projects. To the extent that low-income qualifying projects are not available and projects located on or adjacent to public elementary or secondary schools are available, the remainder of no less than 25 percent of such required percentage shall be composed of projects located on or adjacent to public elementary or secondary schools. A project located on or adjacent to a public elementary or secondary school shall have a contractual relationship with such school in order to qualify for the provisions of this section.

3. Beginning with the 2027 compliance year and thereafter, at least 75 percent of all RECs used by a Phase II Utility in a compliance period shall come from RPS eligible resources located in the Commonwealth.

4. Any Phase I or Phase II Utility may apply renewable energy sales achieved or RECs acquired in excess of the sales requirement for that RPS Program to the sales requirements for RPS Program requirements in the year in which it was generated and the five calendar years after the renewable energy was generated or the RECs were created. To the extent that a Phase I or Phase II Utility procures RECs for RPS Program compliance from resources the utility does not own, the utility shall be entitled to recover the costs of such certificates at its election pursuant to § 56-249.6 or subdivision A 5 d of § 56-585.1 .

5. Energy from a geothermal heating and cooling system is eligible for inclusion in meeting the requirements of the RPS Program. RECs from a geothermal heating and cooling system are created based on the amount of energy, converted from BTUs to kilowatt-hours, that is generated by a geothermal heating and cooling system for space heating and cooling or water heating. The Commission shall determine the form and manner in which such RECs are verified.

D. Each Phase I or Phase II Utility shall petition the Commission for necessary approvals to procure zero-carbon electricity generating capacity as set forth in this subsection and energy storage resources as set forth in subsection E. To the extent that a Phase I or Phase II Utility constructs or acquires new zero-carbon generating facilities or energy storage resources, the utility shall petition the Commission for the recovery of the costs of such facilities, at the utility's election, either through its rates for generation and distribution services or through a rate adjustment clause pursuant to subdivision A 6 of § 56-585.1 . All costs not sought for recovery through a rate adjustment clause pursuant to subdivision A 6 of § 56-585.1 associated with generating facilities provided by sunlight or onshore or offshore wind are also eligible to be applied by the utility as a customer credit reinvestment offset as provided in subdivision A 8 of § 56-585.1 . Costs associated with the purchase of energy, capacity, or environmental attributes from facilities owned by the persons other than the utility required by this subsection shall be recovered by the utility either through its rates for generation and distribution services or pursuant to § 56-249.6 .

1. Each Phase I Utility shall petition the Commission for necessary approvals to construct, acquire, or enter into agreements to purchase the energy, capacity, and environmental attributes of 600 megawatts of generating capacity using energy derived from sunlight or onshore wind.

a. By December 31, 2023, each Phase I Utility shall petition the Commission for necessary approvals to construct, acquire, or enter into agreements to purchase the energy, capacity, and environmental attributes of at least 200 megawatts of generating capacity located in the Commonwealth using energy derived from sunlight or onshore wind, and 35 percent of such generating capacity procured shall be from the purchase of energy, capacity, and environmental attributes from solar or onshore wind facilities owned by persons other than the utility, with the remainder, in the aggregate, being from construction or acquisition by such Phase I Utility.

b. By December 31, 2027, each Phase I Utility shall petition the Commission for necessary approvals to construct, acquire, or enter into agreements to purchase the energy, capacity, and environmental attributes of at least 200 megawatts of additional generating capacity located in the Commonwealth using energy derived from sunlight or onshore wind, and 35 percent of such generating capacity procured shall be from the purchase of energy, capacity, and environmental attributes from solar or onshore wind facilities owned by persons other than the utility, with the remainder, in the aggregate, being from construction or acquisition by such Phase I Utility.

c. By December 31, 2030, each Phase I Utility shall petition the Commission for necessary approvals to construct, acquire, or enter into agreements to purchase the energy, capacity, and environmental attributes of at least 200 megawatts of additional generating capacity located in the Commonwealth using energy derived from sunlight or onshore wind, and 35 percent of such generating capacity procured shall be from the purchase of energy, capacity, and environmental attributes from solar or onshore wind facilities owned by persons other than the utility, with the remainder, in the aggregate, being from construction or acquisition by such Phase I Utility.

d. Nothing in this subdivision 1 shall prohibit such Phase I Utility from constructing, acquiring, or entering into agreements to purchase the energy, capacity, and environmental attributes of more than 600 megawatts of generating capacity located in the Commonwealth using energy derived from sunlight or onshore wind, provided the utility receives approval from the Commission pursuant to §§ 56-580 and 56-585.1 .

2. By December 31, 2035, each Phase II Utility shall petition the Commission for necessary approvals to (i) construct, acquire, or enter into agreements to purchase the energy, capacity, and environmental attributes of 16,100 megawatts of generating capacity located in the Commonwealth using energy derived from sunlight or onshore wind, 35 percent of which generating capacity shall be from the purchase of energy, capacity, and environmental attributes from solar facilities owned by persons other than a utility, including utility affiliates and deregulated affiliates, and (ii) pursuant to § 56-585.1:11 , construct or purchase one or more offshore wind generation facilities located off the Commonwealth's Atlantic shoreline or in federal waters and interconnected directly into the Commonwealth with an aggregate capacity of up to 5,200 megawatts. At least 1,000 megawatts of the 16,100 megawatts shall be placed on previously developed project sites. Thirty-five percent of such generating capacity on previously developed project sites shall be procured from the purchase of energy, capacity, and environmental attributes from solar facilities owned by persons other than a utility, including utility affiliates and deregulated affiliates. The 16,100 megawatts of generating capacity located in the Commonwealth using energy derived from sunlight or onshore wind shall include 1,100 megawatts of solar generation of a nameplate capacity not to exceed three megawatts per individual project, and 65 percent of such generation capacity procured shall be from the purchase of energy, capacity, and environmental attributes from solar facilities owned by persons other than a utility, including utility affiliates and deregulated affiliates.

a. By December 31, 2024, each Phase II Utility shall petition the Commission for necessary approvals to construct, acquire, or enter into agreements to purchase the energy, capacity, and environmental attributes of at least 3,000 megawatts of generating capacity located in the Commonwealth using energy derived from sunlight or onshore wind, and 35 percent of such generating capacity procured shall be from the purchase of energy, capacity, and environmental attributes from solar or onshore wind facilities owned by persons other than the utility, with the remainder, in the aggregate, being from construction or acquisition by such Phase II Utility.

b. By December 31, 2027, each Phase II Utility shall petition the Commission for necessary approvals to construct, acquire, or enter into agreements to purchase the energy, capacity, and environmental attributes of at least 3,000 megawatts of additional generating capacity located in the Commonwealth using energy derived from sunlight or onshore wind, and 35 percent of such generating capacity procured shall be from the purchase of energy, capacity, and environmental attributes from solar or onshore wind facilities owned by persons other than the utility, with the remainder, in the aggregate, being from construction or acquisition by such Phase II Utility.

c. By December 31, 2030, each Phase II Utility shall petition the Commission for necessary approvals to construct, acquire, or enter into agreements to purchase the energy, capacity, and environmental attributes of at least 4,000 megawatts of additional generating capacity located in the Commonwealth using energy derived from sunlight or onshore wind, and 35 percent of such generating capacity procured shall be from the purchase of energy, capacity, and environmental attributes from solar or onshore wind facilities owned by persons other than the utility, with the remainder, in the aggregate, being from construction or acquisition by such Phase II Utility.

d. By December 31, 2035, each Phase II Utility shall petition the Commission for necessary approvals to construct, acquire, or enter into agreements to purchase the energy, capacity, and environmental attributes of at least 6,100 megawatts of additional generating capacity located in the Commonwealth using energy derived from sunlight or onshore wind, and 35 percent of such generating capacity procured shall be from the purchase of energy, capacity, and environmental attributes from solar or onshore wind facilities owned by persons other than the utility, with the remainder, in the aggregate, being from construction or acquisition by such Phase II Utility.

e. Nothing in this subdivision 2 shall prohibit such Phase II Utility from constructing, acquiring, or entering into agreements to purchase the energy, capacity, and environmental attributes of more than 16,100 megawatts of generating capacity located in the Commonwealth using energy derived from sunlight or onshore wind, provided the utility receives approval from the Commission pursuant to §§ 56-580 and 56-585.1 .

3. Nothing in this section shall prohibit a utility from petitioning the Commission to construct or acquire zero-carbon electricity or from entering into contracts to procure the energy, capacity, and environmental attributes of zero-carbon electricity generating resources in excess of the requirements in subsection B. The Commission shall determine whether to approve such petitions on a stand-alone basis pursuant to §§ 56-580 and 56-585.1 , provided that the Commission's review shall also consider whether the proposed generating capacity (i) is necessary to meet the utility's native load, (ii) is likely to lower customer fuel costs, (iii) will provide economic development opportunities in the Commonwealth, and (iv) serves a need that cannot be more affordably met with demand-side or energy storage resources.

Each Phase I and Phase II Utility shall, at least once every year, conduct a request for proposals for new solar, wind, and energy storage resources. Such requests shall quantify and describe the utility's need for energy, capacity, or renewable energy certificates. The requests for proposals shall be publicly announced and made available for public review on the utility's website at least 45 days prior to the closing of such request for proposals. The requests for proposals shall provide, at a minimum, the following information: (a) the size, type, and timing of resources for which the utility anticipates contracting; (b) any minimum thresholds that must be met by respondents; (c) major assumptions to be used by the utility in the bid evaluation process, including environmental emission standards; (d) detailed instructions for preparing bids so that bids can be evaluated on a consistent basis; (e) the preferred general location of additional capacity; and (f) specific information concerning the factors involved in determining the price and non-price criteria used for selecting winning bids. A utility may evaluate responses to requests for proposals based on any criteria that it deems reasonable but shall at a minimum consider the following in its selection process: (1) the status of a particular project's development; (2) the age of existing generation facilities; (3) the demonstrated financial viability of a project and the developer; (4) a developer's prior experience in the field; (5) the location and effect on the transmission grid of a generation facility; (6) benefits to the Commonwealth that are associated with particular projects, including regional economic development and the use of goods and services from Virginia businesses; and (7) the environmental impacts of particular resources, including impacts on air quality within the Commonwealth and the carbon intensity of the utility's generation portfolio.

The Commission shall approve an independent auditor from a list of three auditors proposed by the utility to participate in formulating each criterion for requests for proposals for new energy storage resources and reviewing the results of such requests for proposals. Such independent auditor shall ensure that the Phase I or Phase II Utility purchases projects at the lowest possible cost while ensuring project safety and electric grid reliability. Such independent auditor shall consider and evaluate best practices that are practicable for an electric utility located in the PJM region. In doing so, the independent auditor shall also evaluate the energy storage resources available to and selected by a Phase I or Phase II Utility as compared to the energy storage resources available to and selected by electric utilities in other states or regions of the United States. The independent auditor shall provide a report on such review to the Commission with each annual petition submitted by a Phase I or Phase II Utility under subdivision 4, which report shall be made publicly available on the Commission's website. Upon receiving such report, the Commission may direct the utility to alter its request for proposals to promote affordability, cost savings to customers, and electric grid reliability.

4. In connection with the requirements of this subsection, each Phase I and Phase II Utility shall, commencing in 2020 and concluding in 2045, submit annually a plan and petition for approval for the development of new solar and onshore wind generation capacity. Such plan shall reflect, in the aggregate and over its duration, the requirements of subsection D concerning the allocation percentages for construction or purchase of such capacity. Such petition shall contain any request for approval to construct such facilities pursuant to subsection D of § 56-580 and a request for approval or update of a rate adjustment clause pursuant to subdivision A 6 of § 56-585.1 to recover the costs of such facilities. Such plan shall also include the utility's plan to meet the energy storage project targets of subsection E, including the goal of installing at least 10 percent of such energy storage projects petitioned for pursuant to subdivisions E 1 and 2 behind the meter. In determining whether to approve the utility's plan and any associated petition requests, the Commission shall determine whether they are reasonable and prudent and shall give due consideration to (i) the RPS Program and carbon dioxide reduction requirements in this section; (ii) the promotion of new renewable generation and energy storage resources within the Commonwealth, and associated economic development, including those resources not exceeding three megawatts or placed on previously developed project sites pursuant to subdivision 2; and (iii) fuel savings projected to be achieved by the plan. Notwithstanding any other provision of this title, the Commission's final order regarding any such petition and associated requests shall be entered by the Commission not more than six months after the date of the filing of such petition.

5. If, in any year, a Phase I or Phase II Utility is unable to meet the compliance obligation of the RPS Program requirements or if the cost of RECs necessary to comply with RPS Program requirements exceeds $45 per megawatt hour, such supplier shall be obligated to make a deficiency payment equal to $45 for each megawatt-hour shortfall for the year of noncompliance, except that the deficiency payment for any shortfall in procuring RECs for solar, wind, or anaerobic digesters located in the Commonwealth shall be $75 per megawatt hour for resources one megawatt and lower, and the deficiency payment for any shortfall in procuring RECs for geothermal heating and cooling systems, as required by subdivision C 1 b, shall be $100 per megawatt hour. A Phase I or Phase II Utility shall issue a quarterly request for proposals regarding the procurement of RECs produced by geothermal heating and cooling systems as a portion of its efforts to meet the requirements of subdivision C 1 b. A Phase I or Phase II Utility shall be exempt from making an annual deficiency payment for the quantity of required RECs produced by geothermal heating and cooling systems that are not made available in each request for proposals at a price that is equal to or below the price of such deficiency payment in a compliance year. In any year in which a Phase I or Phase II Utility is exempted from making a deficiency payment resulting from a lack of available RECs from geothermal heating and cooling systems, the utility shall, for that compliance year, procure and retire RPS Program eligible RECs subject to a $45 per megawatt hour deficiency payment in an amount equal to the amount of RECs from geothermal heating and cooling systems that were not made available at a price that was equal to or below $100 per megawatt hour in that compliance year pursuant to subdivision C 1 b. The amount of any deficiency payment shall increase by one percent annually after 2021. A Phase I or Phase II Utility shall be entitled to recover the costs of such payments as a cost of compliance with the requirements of this subsection pursuant to subdivision A 5 d of § 56-585.1 . All proceeds from the deficiency payments shall be deposited into an interest-bearing account administered by the Department of Energy. In administering this account, the Department of Energy shall manage the account as follows: (i) 50 percent of total revenue shall be directed to job training programs in historically economically disadvantaged communities; (ii) 16 percent of total revenue shall be directed to energy efficiency measures for public facilities; (iii) 30 percent of total revenue shall be directed to renewable energy programs located in historically economically disadvantaged communities; and (iv) four percent of total revenue shall be directed to administrative costs.

For any project constructed pursuant to this subsection or subsection E, a utility shall, subject to a competitive procurement process, procure equipment from a Virginia-based or United States-based manufacturer using materials or product components made in Virginia or the United States, if reasonably available and competitively priced.

No later than July 1, 2033, the Commission shall initiate a proceeding to evaluate the future availability of RECs from solar, wind, and anaerobic digestion resources of one megawatt or less located in the Commonwealth in order to meet the renewable portfolio standard requirements of subdivision C 2 and may, in its sole discretion, increase or decrease by up to one percentage point the percentage of a utility's requirements under subdivision C 2 to be met with RECs from such resources in future compliance years.

6. The provisions of this section are in furtherance of the Commonwealth's interest in the health, safety, and welfare of its citizens, including by increasing fuel and resource diversity within the Commonwealth, minimizing the risk and exposure to capacity market pricing volatility, enhancing the reliability and resilience of the Commonwealth's electric system, minimizing emissions of sulfur dioxide, nitrogen oxide, particulate matter, and other pollution that adversely affect public health and the environment in the Commonwealth, and meeting goals to limit carbon dioxide emissions under the laws of the Commonwealth.

E. To enhance reliability and performance of the utility's generation and distribution system, each Phase I and Phase II Utility shall petition the Commission for necessary approvals to construct, acquire, or procure utility-owned energy storage resources. For the purposes of this subsection, "long-duration energy storage" means energy storage resources with 10 hours or more of generation capacity operating at full nameplate capacity and "short-duration energy storage" means energy storage resources with less than 10 hours of generation capacity.

1. By December 31, 2040, each Phase I Utility shall petition the Commission for necessary approvals to construct, acquire, or procure 780 megawatts of short-duration energy storage capacity. Nothing in this subdivision shall prohibit a Phase I Utility from constructing, acquiring, or procuring more than 780 megawatts of short-duration energy storage, provided that the utility receives approval from the Commission pursuant to §§ 56-580 and 56-585.1 . Each Phase I Utility shall petition for at least 10 percent of all short-duration energy storage required by this subdivision to be recovered as electric distribution grid transformation projects in Commission filings conducted pursuant to subdivision A 6 of § 56-585.1 .

2. By December 31, 2045, each Phase II Utility shall petition the Commission for necessary approvals to construct or acquire 16,000 megawatts of short-duration energy storage capacity, including 4,000 megawatts of short-duration energy storage capacity that shall be petitioned for by December 31, 2030. Nothing in this subdivision shall prohibit a Phase II Utility from constructing, acquiring, or procuring more short-duration energy storage than required by this subdivision, provided that the utility receives approval from the Commission pursuant to §§ 56-580 and 56-585.1 . Each Phase II Utility shall petition for at least 10 percent of all short-duration energy storage required by this subdivision to be recovered as electric distribution grid transformation projects in Commission filings conducted pursuant to subdivision A 6 of § 56-585.1 .

3. (Effective pursuant to Acts 2026, cc. 694, 695, cl. 4) By December 31, 2045, each Phase I Utility shall petition the Commission for necessary approvals to construct, acquire, or procure 520 megawatts of long-duration energy storage capacity, half of which shall be petitioned to the Commission for necessary approvals to be constructed, acquired, or procured by December 31, 2035. Of such 520 megawatts, half shall have between 10 and 24 hours of storage capacity and the other half shall have more than 24 hours of storage capacity. Nothing in this subdivision shall prohibit a Phase I Utility from constructing, acquiring, or procuring more than 520 megawatts of long-duration energy storage, provided that the utility receives approval from the Commission pursuant to §§ 56-580 and 56-585.1 .

4. (Effective pursuant to Acts 2026, cc. 694, 695, cl. 4) By December 31, 2045, each Phase II Utility shall petition the Commission for necessary approvals to construct, acquire, or procure 4,000 megawatts of long-duration energy storage capacity, half of which shall be petitioned to the Commission for necessary approvals to be constructed, acquired, or procured by December 31, 2035. Of such 4,000 megawatts, (i) half shall have between 10 and 24 hours of storage capacity and the other half shall have more than 24 hours of storage capacity and (ii) at least 20 percent shall be located in the coalfield region of the Commonwealth, as described in § 15.2-6002 . Nothing in this subdivision shall prohibit a Phase II Utility from constructing, acquiring, or procuring more than 4,000 megawatts of long-duration energy storage, provided that the utility receives approval from the Commission pursuant to §§ 56-580 and 56-585.1 .

5. For all energy storage projects proposed for construction, acquisition, or procurement pursuant to this subsection, the Phase I or Phase II Utility shall demonstrate compliance with the minimum safety standards set forth in the most recently published edition of the National Fire Protection Association 855 Standard for the Installation of Stationary Energy Storage Systems.

6. No single energy storage project shall exceed 500 megawatts in size, except that a Phase II Utility may procure a single energy storage project up to 800 megawatts.

7. All energy storage projects constructed, acquired, or procured pursuant to this subsection shall meet the competitive procurement protocols established in subdivision D 3. For all such energy storage projects, the utility shall demonstrate to the Commission that its procurement sought proposals for both the purchase of storage capacity and the purchase of storage facilities and evaluated the comparative costs, risk allocation, ownership implications, and impact on customers of each proposal received.

8. After July 1, 2020, at least 35 percent of the energy storage facilities placed into service shall be (i) purchased by the public utility from a party other than the public utility or (ii) owned by a party other than a public utility, with the capacity from such facilities sold to the public utility. By January 1, 2027, the Commission shall adopt regulations to achieve the deployment of energy storage for the Commonwealth required in subdivisions 1 and 2, including regulations that set interim targets from 2031 until 2045 and update existing utility planning and procurement rules. The regulations shall include programs and mechanisms to deploy energy storage, including competitive solicitations, behind-the-meter incentives, non-wires alternatives programs, and peak demand reduction programs. The Commission shall update such regulations no less frequently than every five years.

9. If a Phase I or Phase II Utility newly acquires the right, by contract or otherwise, to energy storage capacity from pumped storage facilities located in the Commonwealth, or makes investments to increase the electrical capacity of any such facility, such newly acquired or increased pumped storage capacity shall count toward the requirements of subdivision E 1 or 2 of § 56-585.5 .

F. All costs incurred by a Phase I or Phase II Utility related to compliance with the requirements of this section or pursuant to § 56-585.1:11 , including (i) costs of generation facilities powered by sunlight or onshore or offshore wind, or energy storage facilities, that are constructed or acquired by a Phase I or Phase II Utility after July 1, 2020, (ii) costs of capacity, energy, or environmental attributes from generation facilities powered by sunlight or onshore or offshore wind, or falling water, or energy storage facilities purchased by the utility from persons other than the utility through agreements after July 1, 2020, and (iii) all other costs of compliance, including costs associated with the purchase of RECs associated with RPS Program requirements pursuant to this section shall be recovered from all retail customers in the service territory of a Phase I or Phase II Utility as a non-bypassable charge, irrespective of the generation supplier of such customer, except (a) as provided in subsection G for an accelerated clean energy buyer or (b) as provided in subdivision C 3 of § 56-585.1:11 , with respect to the costs of an offshore wind generation facility, for a PIPP eligible utility customer or an advanced clean energy buyer or qualifying large general service customer, as those terms are defined in § 56-585.1:11 . If a Phase I or Phase II Utility serves customers in more than one jurisdiction, such utility shall recover all of the costs of compliance with the RPS Program requirements from its Virginia customers through the applicable cost recovery mechanism, and all associated energy, capacity, and environmental attributes shall be assigned to Virginia to the extent that such costs are requested but not recovered from any system customers outside the Commonwealth.

By September 1, 2020, the Commission shall direct the initiation of a proceeding for each Phase I and Phase II Utility to review and determine the amount of such costs, net of benefits, that should be allocated to retail customers within the utility's service territory which have elected to receive electric supply service from a supplier of electric energy other than the utility, and shall direct that tariff provisions be implemented to recover those costs from such customers beginning no later than January 1, 2021. Thereafter, such charges and tariff provisions shall be updated and trued up by the utility on an annual basis, subject to continuing review and approval by the Commission.

G. 1. An accelerated clean energy buyer may contract with a Phase I or Phase II Utility, or a person other than a Phase I or Phase II Utility, to obtain (i) RECs from RPS Program eligible resources or (ii) bundled capacity, energy, and RECs from or wind generation resources located within the PJM region and initially placed in commercial operation after January 1, 2015, including any contract with a utility for such generation resources that does not allocate the cost of such resources to or recover the cost of such resources from any other customers of the utility that have not voluntarily agreed to pay such cost. Beginning July 1, 2026, an accelerated clean energy buyer that is a customer of a Phase I or Phase II Utility may also contract with a Phase I or Phase II Utility, or a person other than a Phase I or Phase II Utility, to obtain zero-carbon electricity from generation resources located within the PJM region and initially placed in commercial operation after January 1, 2015, or placed in commercial operation on or before January 1, 2015, if investments to increase the maximum thermal power output of such facility resulted in the generation of new electricity after July 1, 2026, or if a financial agreement for procurement of energy and capacity was entered into with such facility after July 1, 2026, to prevent the previously announced early retirement or decommissioning of such facility due to financial constraints. Such an accelerated clean energy buyer may offset all or a portion of its electric load for purposes of RPS Program compliance through such arrangements. An accelerated clean energy buyer obtaining capacity, energy, or RECs from qualifying solar, wind, or zero-carbon electricity generation resources or energy storage facilities shall be exempt from the assignment of non-bypassable RPS Program compliance costs pursuant to subsection F, with the exception of the costs of an offshore wind generating facility pursuant to § 56-585.1:11 , based on the amount (i) RECs from generation resources located within the PJM region and (ii) zero-carbon electricity from generation resources located within the Commonwealth obtained pursuant to this subsection in proportion to the customer's total electric energy consumption, on an annual basis. An accelerated clean energy buyer obtaining bundled capacity or energy from zero-carbon electricity generation resources located within the PJM region but not located within the Commonwealth shall only be exempt from the assignment of non-bypassable RPS Program compliance costs pursuant to subdivision F that are associated with the purchase of RECs required for RPS Program compliance, based on the amount of zero-carbon electric energy obtained pursuant to this subsection in proportion to the customer's total electric energy consumption, on an annual basis. An accelerated clean energy buyer may also contract with a Phase I or Phase II Utility, or a person other than a Phase I or Phase II Utility, to obtain capacity from energy storage facilities located within the network service area of the utility pursuant to this subsection, provided that the costs of such resources are not recovered from any of the utility's customers who have not voluntarily agreed to pay for such costs. Such accelerated clean energy buyer shall be exempt from the assignment of non-bypassable RPS Program compliance costs specifically associated with energy storage facilities pursuant to this subsection in proportion to the customer's total capacity demand on an annual basis. An accelerated clean energy buyer obtaining RECs only shall not be exempt from costs related to procurement of new solar or onshore wind generation capacity, energy, or environmental attributes, or energy storage facilities, by the utility pursuant to subsections D and E, however, an accelerated clean energy buyer that is a customer of a Phase II Utility and was subscribed, as of March 1, 2020, to a voluntary companion experimental tariff offering of the utility for the purchase of renewable attributes from renewable energy facilities that requires a renewable facilities agreement and the purchase of a minimum of 2,000 renewable attributes annually, shall be exempt from allocation of the net costs related to procurement of new solar or onshore wind generation capacity, energy, or environmental attributes, or energy storage facilities, by the utility pursuant to subsections D and E, based on the amount of RECs associated with the customer's renewable facilities agreements associated with such tariff offering as of that date in proportion to the customer's total electric energy consumption, on an annual basis. To the extent that an accelerated clean energy buyer contracts for the capacity of new solar or wind generation resources or energy storage facilities pursuant to this subsection, the aggregate amount of such nameplate capacity shall be offset from the utility's procurement requirements pursuant to subsection D. All RECs associated with contracts entered into by an accelerated clean energy buyer with the utility, or a person other than the utility, for an RPS Program shall not be credited to the utility's compliance with its RPS Program requirements, and the calculation of the utility's RPS Program requirements shall not include the electric load covered by customers certified as accelerated clean energy buyers.

2. Each Phase I or Phase II Utility shall certify, and verify as necessary, to the Commission that the accelerated clean energy buyer has satisfied the exemption requirements of this subsection for each year, or an accelerated clean energy buyer may choose to certify satisfaction of this exemption by reporting to the Commission individually. The Commission may promulgate such rules and regulations as may be necessary to implement the provisions of this subsection.

3. Provided that no incremental costs associated with any contract between a Phase I or Phase II Utility and an accelerated clean energy buyer is allocated to or recovered from any other customer of the utility, any such contract with an accelerated clean energy buyer that is a jurisdictional customer of the utility shall not be deemed a special rate or contract requiring Commission approval pursuant to § 56-235.2 .

4. The Commission shall ensure that any distribution and transmission costs associated with new energy generation resources procured pursuant to this subsection are justly and reasonably allocated.

H. No customer of a Phase II Utility with a peak demand in excess of 100 megawatts in 2019 that elected pursuant to subdivision A 3 of § 56-577 to purchase electric energy from a competitive service provider prior to April 1, 2019, shall be allocated any non-bypassable charges pursuant to subsection F for such period that the customer is not purchasing electric energy from the utility, and such customer's electric load shall not be included in the utility's RPS Program requirements. No customer of a Phase I Utility that elected pursuant to subdivision A 3 of § 56-577 to purchase electric energy from a competitive service provider prior to February 1, 2019, shall be allocated any non-bypassable charges pursuant to subsection F for such period that the customer is not purchasing electric energy from the utility, and such customer's electric load shall not be included in the utility's RPS Program requirements.

I. In any petition by a Phase I or Phase II Utility for a certificate of public convenience and necessity to construct and operate an electrical generating facility that generates electric energy derived from sunlight submitted pursuant to § 56-580 , such utility shall demonstrate that the proposed facility was subject to competitive procurement or solicitation as set forth in subdivision D 3.

J. Notwithstanding any contrary provision of law, for the purposes of this section, any falling water generation facility located in the Commonwealth and commencing commercial operations prior to July 1, 2024, shall be considered a renewable energy portfolio standard (RPS Program) eligible source.

K. Nothing in this section shall apply to any entity organized under Chapter 9.1 (§ 56-231.15 et seq.).

L. The Commission shall adopt such rules and regulations as may be necessary to implement the provisions of this section, including a requirement that participants verify whether the RPS Program requirements are met in accordance with this section.

2020, cc. 1193 , 1194 ; 2021, Sp. Sess. I, cc. 140 , 328 , 532 ; 2023, cc. 732 , 803 , 804 ; 2024, cc. 596 , 597 ; 2025, cc. 707 , 708 , 713 , 714 ; 2026, cc. 43 , 512 , 645 , 646 , 694 , 695 , 733 , 734 .

A. As used in this section:

"Accelerated clean energy buyer" means a commercial or industrial customer of a Phase I or Phase II Utility, irrespective of generation supplier, with an aggregate load over 25 megawatts in the prior calendar year, that enters into arrangements pursuant to subsection G, as certified by the Commission.

"Aggregate load" means the combined electrical load associated with selected accounts of an accelerated clean energy buyer with the same legal entity name as, or in the names of affiliated entities that control, are controlled by, or are under common control of, such legal entity or are the names of affiliated entities under a common parent.

"Control" has the same meaning as provided in § 56-585.1:11 .

"Elementary or secondary" has the same meaning as provided in § 22.1-1 .

"Falling water" means hydroelectric resources, including run-of-river generation from a combined pumped-storage and run-of-river facility. "Falling water" does not include electricity generated from pumped-storage facilities.

"Low-income qualifying projects" means a project that provides a minimum of 50 percent of the respective electric output to low-income utility customers as that term is defined in § 56-576 .

"Phase I Utility" has the same meaning as provided in subdivision A 1 of § 56-585.1 .

"Phase II Utility" has the same meaning as provided in subdivision A 1 of § 56-585.1 .

"Previously developed project site" means any property, including related buffer areas, if any, that has been previously disturbed or developed for non-single-family residential, nonagricultural, or nonsilvicultural use, regardless of whether such property currently is being used for any purpose. "Previously developed project site" includes a brownfield as defined in § 10.1-1230 or any parcel that has been previously used (i) for a retail, commercial, or industrial purpose; (ii) as a parking lot; (iii) as the site of a parking lot canopy or structure; (iv) for mining, which is any lands affected by coal mining that took place before August 3, 1977, or any lands upon which extraction activities have been permitted by the Department of Energy under Title 45.2; (v) for quarrying; or (vi) as a landfill.

"Total electric energy" means total electric energy sold to retail customers in the Commonwealth service territory of a Phase I or Phase II Utility, other than accelerated clean energy buyers, by the incumbent electric utility or other retail supplier of electric energy in the previous calendar year, excluding an amount equivalent to the annual percentages of the electric energy that was supplied to such customer from nuclear generating plants located within the Commonwealth in the previous calendar year, provided such nuclear units were operating by July 1, 2020, or from any zero-carbon electric generating facilities not otherwise RPS eligible sources and placed into service in the Commonwealth after July 1, 2030.

"Zero-carbon electricity" means electricity generated by any generating unit that does not emit carbon dioxide as a by-product of combusting fuel to generate electricity.

B. 1. By December 31, 2024, except for any coal-fired electric generating units (i) jointly owned with a cooperative utility or (ii) owned and operated by a Phase II Utility located in the coalfield region of the Commonwealth that co-fires with biomass, any Phase I and Phase II Utility shall retire all generating units principally fueled by oil with a rated capacity in excess of 500 megawatts and all coal-fired electric generating units operating in the Commonwealth.

2. By December 31, 2045, except for biomass-fired electric generating units that do not co-fire with coal, each Phase I and II Utility shall retire all other electric generating units located in the Commonwealth that emit carbon as a by-product of combusting fuel to generate electricity.

3. A Phase I or Phase II Utility may petition the Commission for relief from the requirements of this subsection on the basis that the requirement would threaten the reliability or security of electric service to customers. The Commission shall consider in-state and regional transmission entity resources and shall evaluate the reliability of each proposed retirement on a case-by-case basis in ruling upon any such petition.

C. Each Phase I and Phase II Utility shall participate in a renewable energy portfolio standard program (RPS Program) that establishes annual goals for the sale of renewable energy to all retail customers in the utility's service territory, other than accelerated clean energy buyers pursuant to subsection G, regardless of whether such customers purchase electric supply service from the utility or from suppliers other than the utility. To comply with the RPS Program, each Phase I and Phase II Utility shall procure and retire Renewable Energy Certificates (RECs) originating from renewable energy portfolio standard eligible sources (RPS eligible sources). For purposes of complying with the RPS Program from 2021 to 2024, a Phase I and Phase II Utility may use RECs from any renewable energy facility, as defined in § 56-576 , provided that such facilities are located in the Commonwealth or are physically located within the PJM Interconnection, LLC (PJM) region. However, at no time during this period or thereafter may any Phase I or Phase II Utility use RECs from (i) renewable thermal energy, (ii) renewable thermal energy equivalent, or (iii) biomass-fired facilities that are outside the Commonwealth. From compliance year 2025 and all years after, each Phase I and Phase II Utility may only use RECs from RPS eligible sources for compliance with the RPS Program.

In order to qualify as RPS eligible sources, such sources must be (a) electric-generating resources that generate electric energy derived from solar or wind located in the Commonwealth or off the Commonwealth's Atlantic shoreline or in federal waters and interconnected directly into the Commonwealth or physically located within the PJM region; (b) falling water resources located in the Commonwealth or physically located within the PJM region that were in operation as of January 1, 2020, that are owned by a Phase I or Phase II Utility or for which a Phase I or Phase II Utility has entered into a contract prior to January 1, 2020, to purchase the energy, capacity, and renewable attributes of such falling water resources; (c) non-utility-owned resources from falling water that (1) are less than 65 megawatts, (2) began commercial operation after December 31, 1979, or (3) added incremental generation representing greater than 50 percent of the original nameplate capacity after December 31, 1979, provided that such resources are located in the Commonwealth or are physically located within the PJM region; (d) waste-to-energy or landfill gas-fired generating resources located in the Commonwealth and in operation as of January 1, 2020, provided that such resources do not use waste heat from fossil fuel combustion; (e) geothermal heating and cooling systems located in the Commonwealth; (f) geothermal electric generating resources located in the Commonwealth or physically located within the PJM region; or (g) biomass-fired facilities in operation in the Commonwealth and in operation as of January 1, 2023, that (1) supply no more than 10 percent of their annual net electrical generation to the electric grid or no more than 15 percent of their annual total useful energy to any entity other than the manufacturing facility to which the generating source is interconnected and are fueled by forest-product manufacturing residuals, including pulping liquor, bark, paper recycling residuals, biowastes, or biomass, as described in subdivisions A 1, 2, and 4 of § 10.1-1308.1 , provided that biomass as described in subdivision A 1 of § 10.1-1308.1 results from harvesting in accordance with best management practices for the sustainable harvesting of biomass developed and enforced by the State Forester pursuant to § 10.1-1105 , or (2) are owned by a Phase I or Phase II Utility, have less than 52 megawatts capacity, and are fueled by forest-product manufacturing residuals, biowastes, or biomass, as described in subdivisions A 1, 2, and 4 of § 10.1-1308.1 , provided that biomass as described in subdivision A 1 of § 10.1-1308.1 results from harvesting in accordance with best management practices for the sustainable harvesting of biomass developed and enforced by the State Forester pursuant to § 10.1-1105 . Regardless of any future maintenance, expansion, or refurbishment activities, the total amount of RECs that may be sold by any RPS eligible source using biomass in any year shall be no more than the number of megawatt hours of electricity produced by that facility in 2022; however, in no year may any RPS eligible source using biomass sell RECs in excess of the actual megawatt-hours of electricity generated by such facility that year. In order to comply with the RPS Program, each Phase I and Phase II Utility may use and retire the environmental attributes associated with any existing owned or contracted solar, wind, falling water, or biomass electric generating resources in operation, or proposed for operation, in the Commonwealth or solar, wind, or falling water resources physically located within the PJM region, with such resource qualifying as a Commonwealth-located resource for purposes of this subsection, as of January 1, 2020, provided that such renewable attributes are verified as RECs consistent with the PJM-EIS Generation Attribute Tracking System.

1. a. The RPS Program requirements shall be a percentage of the total electric energy sold in the previous calendar year and shall be implemented in accordance with the following schedule:

b. Beginning with the 2027 compliance year and thereafter, each Phase II Utility shall procure and retire RECs from geothermal heating and cooling systems located in the Commonwealth, as a percentage of the total number of RECs used for RPS program compliance, in the following amounts, at minimum: (i) 0.5 percent in 2027, (ii) 0.75 percent in 2028, and (iii) one percent in and after 2029. Beginning with the 2027 compliance year and thereafter, each Phase I Utility shall procure and retire RECs from geothermal heating and cooling systems located within its own service territory, as a percentage of the total number of RECs used for RPS program compliance, in the following amounts, at minimum: (a) 0.5 percent in 2027, (b) 0.75 percent in 2028, and (c) one percent in and after 2029.

2. A Phase II Utility shall meet the RPS Program requirements in any given compliance year with solar, wind, or anaerobic digestion resources of one megawatt or less located in the Commonwealth, measured as a percentage of the Phase II Utility's RPS Program requirements: (i) 4.5 percent for the 2026 through 2030 compliance years and (ii) five percent for the 2031 through 2045 compliance years. No more than 3,000 kilowatts of any such solar, wind, or anaerobic digestion resources may be located at any single location or at contiguous locations owned by the same entity or affiliated entities, and, to the extent that low-income qualifying projects are available, no less than 25 percent of such required percentage shall be composed of low-income qualifying projects. To the extent that low-income qualifying projects are not available and projects located on or adjacent to public elementary or secondary schools are available, the remainder of no less than 25 percent of such required percentage shall be composed of projects located on or adjacent to public elementary or secondary schools. A project located on or adjacent to a public elementary or secondary school shall have a contractual relationship with such school in order to qualify for the provisions of this section.

3. Beginning with the 2027 compliance year and thereafter, at least 75 percent of all RECs used by a Phase II Utility in a compliance period shall come from RPS eligible resources located in the Commonwealth.

4. Any Phase I or Phase II Utility may apply renewable energy sales achieved or RECs acquired in excess of the sales requirement for that RPS Program to the sales requirements for RPS Program requirements in the year in which it was generated and the five calendar years after the renewable energy was generated or the RECs were created. To the extent that a Phase I or Phase II Utility procures RECs for RPS Program compliance from resources the utility does not own, the utility shall be entitled to recover the costs of such certificates at its election pursuant to § 56-249.6 or subdivision A 5 d of § 56-585.1 .

5. Energy from a geothermal heating and cooling system is eligible for inclusion in meeting the requirements of the RPS Program. RECs from a geothermal heating and cooling system are created based on the amount of energy, converted from BTUs to kilowatt-hours, that is generated by a geothermal heating and cooling system for space heating and cooling or water heating. The Commission shall determine the form and manner in which such RECs are verified.

D. Each Phase I or Phase II Utility shall petition the Commission for necessary approvals to procure zero-carbon electricity generating capacity as set forth in this subsection and energy storage resources as set forth in subsection E. To the extent that a Phase I or Phase II Utility constructs or acquires new zero-carbon generating facilities or energy storage resources, the utility shall petition the Commission for the recovery of the costs of such facilities, at the utility's election, either through its rates for generation and distribution services or through a rate adjustment clause pursuant to subdivision A 6 of § 56-585.1 . All costs not sought for recovery through a rate adjustment clause pursuant to subdivision A 6 of § 56-585.1 associated with generating facilities provided by sunlight or onshore or offshore wind are also eligible to be applied by the utility as a customer credit reinvestment offset as provided in subdivision A 8 of § 56-585.1 . Costs associated with the purchase of energy, capacity, or environmental attributes from facilities owned by the persons other than the utility required by this subsection shall be recovered by the utility either through its rates for generation and distribution services or pursuant to § 56-249.6 .

1. Each Phase I Utility shall petition the Commission for necessary approvals to construct, acquire, or enter into agreements to purchase the energy, capacity, and environmental attributes of 600 megawatts of generating capacity using energy derived from sunlight or onshore wind.

a. By December 31, 2023, each Phase I Utility shall petition the Commission for necessary approvals to construct, acquire, or enter into agreements to purchase the energy, capacity, and environmental attributes of at least 200 megawatts of generating capacity located in the Commonwealth using energy derived from sunlight or onshore wind, and 35 percent of such generating capacity procured shall be from the purchase of energy, capacity, and environmental attributes from solar or onshore wind facilities owned by persons other than the utility, with the remainder, in the aggregate, being from construction or acquisition by such Phase I Utility.

b. By December 31, 2027, each Phase I Utility shall petition the Commission for necessary approvals to construct, acquire, or enter into agreements to purchase the energy, capacity, and environmental attributes of at least 200 megawatts of additional generating capacity located in the Commonwealth using energy derived from sunlight or onshore wind, and 35 percent of such generating capacity procured shall be from the purchase of energy, capacity, and environmental attributes from solar or onshore wind facilities owned by persons other than the utility, with the remainder, in the aggregate, being from construction or acquisition by such Phase I Utility.

c. By December 31, 2030, each Phase I Utility shall petition the Commission for necessary approvals to construct, acquire, or enter into agreements to purchase the energy, capacity, and environmental attributes of at least 200 megawatts of additional generating capacity located in the Commonwealth using energy derived from sunlight or onshore wind, and 35 percent of such generating capacity procured shall be from the purchase of energy, capacity, and environmental attributes from solar or onshore wind facilities owned by persons other than the utility, with the remainder, in the aggregate, being from construction or acquisition by such Phase I Utility.

d. Nothing in this subdivision 1 shall prohibit such Phase I Utility from constructing, acquiring, or entering into agreements to purchase the energy, capacity, and environmental attributes of more than 600 megawatts of generating capacity located in the Commonwealth using energy derived from sunlight or onshore wind, provided the utility receives approval from the Commission pursuant to §§ 56-580 and 56-585.1 .

2. By December 31, 2035, each Phase II Utility shall petition the Commission for necessary approvals to (i) construct, acquire, or enter into agreements to purchase the energy, capacity, and environmental attributes of 16,100 megawatts of generating capacity located in the Commonwealth using energy derived from sunlight or onshore wind, 35 percent of which generating capacity shall be from the purchase of energy, capacity, and environmental attributes from solar facilities owned by persons other than a utility, including utility affiliates and deregulated affiliates, and (ii) pursuant to § 56-585.1:11 , construct or purchase one or more offshore wind generation facilities located off the Commonwealth's Atlantic shoreline or in federal waters and interconnected directly into the Commonwealth with an aggregate capacity of up to 5,200 megawatts. At least 1,000 megawatts of the 16,100 megawatts shall be placed on previously developed project sites. Thirty-five percent of such generating capacity on previously developed project sites shall be procured from the purchase of energy, capacity, and environmental attributes from solar facilities owned by persons other than a utility, including utility affiliates and deregulated affiliates. The 16,100 megawatts of generating capacity located in the Commonwealth using energy derived from sunlight or onshore wind shall include 1,100 megawatts of solar generation of a nameplate capacity not to exceed three megawatts per individual project, and 65 percent of such generation capacity procured shall be from the purchase of energy, capacity, and environmental attributes from solar facilities owned by persons other than a utility, including utility affiliates and deregulated affiliates.

a. By December 31, 2024, each Phase II Utility shall petition the Commission for necessary approvals to construct, acquire, or enter into agreements to purchase the energy, capacity, and environmental attributes of at least 3,000 megawatts of generating capacity located in the Commonwealth using energy derived from sunlight or onshore wind, and 35 percent of such generating capacity procured shall be from the purchase of energy, capacity, and environmental attributes from solar or onshore wind facilities owned by persons other than the utility, with the remainder, in the aggregate, being from construction or acquisition by such Phase II Utility.

b. By December 31, 2027, each Phase II Utility shall petition the Commission for necessary approvals to construct, acquire, or enter into agreements to purchase the energy, capacity, and environmental attributes of at least 3,000 megawatts of additional generating capacity located in the Commonwealth using energy derived from sunlight or onshore wind, and 35 percent of such generating capacity procured shall be from the purchase of energy, capacity, and environmental attributes from solar or onshore wind facilities owned by persons other than the utility, with the remainder, in the aggregate, being from construction or acquisition by such Phase II Utility.

c. By December 31, 2030, each Phase II Utility shall petition the Commission for necessary approvals to construct, acquire, or enter into agreements to purchase the energy, capacity, and environmental attributes of at least 4,000 megawatts of additional generating capacity located in the Commonwealth using energy derived from sunlight or onshore wind, and 35 percent of such generating capacity procured shall be from the purchase of energy, capacity, and environmental attributes from solar or onshore wind facilities owned by persons other than the utility, with the remainder, in the aggregate, being from construction or acquisition by such Phase II Utility.

d. By December 31, 2035, each Phase II Utility shall petition the Commission for necessary approvals to construct, acquire, or enter into agreements to purchase the energy, capacity, and environmental attributes of at least 6,100 megawatts of additional generating capacity located in the Commonwealth using energy derived from sunlight or onshore wind, and 35 percent of such generating capacity procured shall be from the purchase of energy, capacity, and environmental attributes from solar or onshore wind facilities owned by persons other than the utility, with the remainder, in the aggregate, being from construction or acquisition by such Phase II Utility.

e. Nothing in this subdivision 2 shall prohibit such Phase II Utility from constructing, acquiring, or entering into agreements to purchase the energy, capacity, and environmental attributes of more than 16,100 megawatts of generating capacity located in the Commonwealth using energy derived from sunlight or onshore wind, provided the utility receives approval from the Commission pursuant to §§ 56-580 and 56-585.1 .

3. Nothing in this section shall prohibit a utility from petitioning the Commission to construct or acquire zero-carbon electricity or from entering into contracts to procure the energy, capacity, and environmental attributes of zero-carbon electricity generating resources in excess of the requirements in subsection B. The Commission shall determine whether to approve such petitions on a stand-alone basis pursuant to §§ 56-580 and 56-585.1 , provided that the Commission's review shall also consider whether the proposed generating capacity (i) is necessary to meet the utility's native load, (ii) is likely to lower customer fuel costs, (iii) will provide economic development opportunities in the Commonwealth, and (iv) serves a need that cannot be more affordably met with demand-side or energy storage resources.

Each Phase I and Phase II Utility shall, at least once every year, conduct a request for proposals for new solar, wind, and energy storage resources. Such requests shall quantify and describe the utility's need for energy, capacity, or renewable energy certificates. The requests for proposals shall be publicly announced and made available for public review on the utility's website at least 45 days prior to the closing of such request for proposals. The requests for proposals shall provide, at a minimum, the following information: (a) the size, type, and timing of resources for which the utility anticipates contracting; (b) any minimum thresholds that must be met by respondents; (c) major assumptions to be used by the utility in the bid evaluation process, including environmental emission standards; (d) detailed instructions for preparing bids so that bids can be evaluated on a consistent basis; (e) the preferred general location of additional capacity; and (f) specific information concerning the factors involved in determining the price and non-price criteria used for selecting winning bids. A utility may evaluate responses to requests for proposals based on any criteria that it deems reasonable but shall at a minimum consider the following in its selection process: (1) the status of a particular project's development; (2) the age of existing generation facilities; (3) the demonstrated financial viability of a project and the developer; (4) a developer's prior experience in the field; (5) the location and effect on the transmission grid of a generation facility; (6) benefits to the Commonwealth that are associated with particular projects, including regional economic development and the use of goods and services from Virginia businesses; and (7) the environmental impacts of particular resources, including impacts on air quality within the Commonwealth and the carbon intensity of the utility's generation portfolio.

The Commission shall approve an independent auditor from a list of three auditors proposed by the utility to participate in formulating each criterion for requests for proposals for new energy storage resources and reviewing the results of such requests for proposals. Such independent auditor shall ensure that the Phase I or Phase II Utility purchases projects at the lowest possible cost while ensuring project safety and electric grid reliability. Such independent auditor shall consider and evaluate best practices that are practicable for an electric utility located in the PJM region. In doing so, the independent auditor shall also evaluate the energy storage resources available to and selected by a Phase I or Phase II Utility as compared to the energy storage resources available to and selected by electric utilities in other states or regions of the United States. The independent auditor shall provide a report on such review to the Commission with each annual petition submitted by a Phase I or Phase II Utility under subdivision 4, which report shall be made publicly available on the Commission's website. Upon receiving such report, the Commission may direct the utility to alter its request for proposals to promote affordability, cost savings to customers, and electric grid reliability.

4. In connection with the requirements of this subsection, each Phase I and Phase II Utility shall, commencing in 2020 and concluding in 2045, submit annually a plan and petition for approval for the development of new solar and onshore wind generation capacity. Such plan shall reflect, in the aggregate and over its duration, the requirements of subsection D concerning the allocation percentages for construction or purchase of such capacity. Such petition shall contain any request for approval to construct such facilities pursuant to subsection D of § 56-580 and a request for approval or update of a rate adjustment clause pursuant to subdivision A 6 of § 56-585.1 to recover the costs of such facilities. Such plan shall also include the utility's plan to meet the energy storage project targets of subsection E, including the goal of installing at least 10 percent of such energy storage projects petitioned for pursuant to subdivisions E 1 and 2 behind the meter. In determining whether to approve the utility's plan and any associated petition requests, the Commission shall determine whether they are reasonable and prudent and shall give due consideration to (i) the RPS Program and carbon dioxide reduction requirements in this section; (ii) the promotion of new renewable generation and energy storage resources within the Commonwealth, and associated economic development, including those resources not exceeding three megawatts or placed on previously developed project sites pursuant to subdivision 2; and (iii) fuel savings projected to be achieved by the plan. Notwithstanding any other provision of this title, the Commission's final order regarding any such petition and associated requests shall be entered by the Commission not more than six months after the date of the filing of such petition.

5. If, in any year, a Phase I or Phase II Utility is unable to meet the compliance obligation of the RPS Program requirements or if the cost of RECs necessary to comply with RPS Program requirements exceeds $45 per megawatt hour, such supplier shall be obligated to make a deficiency payment equal to $45 for each megawatt-hour shortfall for the year of noncompliance, except that the deficiency payment for any shortfall in procuring RECs for solar, wind, or anaerobic digesters located in the Commonwealth shall be $75 per megawatt hour for resources one megawatt and lower, and the deficiency payment for any shortfall in procuring RECs for geothermal heating and cooling systems, as required by subdivision C 1 b, shall be $100 per megawatt hour. A Phase I or Phase II Utility shall issue a quarterly request for proposals regarding the procurement of RECs produced by geothermal heating and cooling systems as a portion of its efforts to meet the requirements of subdivision C 1 b. A Phase I or Phase II Utility shall be exempt from making an annual deficiency payment for the quantity of required RECs produced by geothermal heating and cooling systems that are not made available in each request for proposals at a price that is equal to or below the price of such deficiency payment in a compliance year. In any year in which a Phase I or Phase II Utility is exempted from making a deficiency payment resulting from a lack of available RECs from geothermal heating and cooling systems, the utility shall, for that compliance year, procure and retire RPS Program eligible RECs subject to a $45 per megawatt hour deficiency payment in an amount equal to the amount of RECs from geothermal heating and cooling systems that were not made available at a price that was equal to or below $100 per megawatt hour in that compliance year pursuant to subdivision C 1 b. The amount of any deficiency payment shall increase by one percent annually after 2021. A Phase I or Phase II Utility shall be entitled to recover the costs of such payments as a cost of compliance with the requirements of this subsection pursuant to subdivision A 5 d of § 56-585.1 . All proceeds from the deficiency payments shall be deposited into an interest-bearing account administered by the Department of Energy. In administering this account, the Department of Energy shall manage the account as follows: (i) 50 percent of total revenue shall be directed to job training programs in historically economically disadvantaged communities; (ii) 16 percent of total revenue shall be directed to energy efficiency measures for public facilities; (iii) 30 percent of total revenue shall be directed to renewable energy programs located in historically economically disadvantaged communities; and (iv) four percent of total revenue shall be directed to administrative costs.

For any project constructed pursuant to this subsection or subsection E, a utility shall, subject to a competitive procurement process, procure equipment from a Virginia-based or United States-based manufacturer using materials or product components made in Virginia or the United States, if reasonably available and competitively priced.

No later than July 1, 2033, the Commission shall initiate a proceeding to evaluate the future availability of RECs from solar, wind, and anaerobic digestion resources of one megawatt or less located in the Commonwealth in order to meet the renewable portfolio standard requirements of subdivision C 2 and may, in its sole discretion, increase or decrease by up to one percentage point the percentage of a utility's requirements under subdivision C 2 to be met with RECs from such resources in future compliance years.

6. The provisions of this section are in furtherance of the Commonwealth's interest in the health, safety, and welfare of its citizens, including by increasing fuel and resource diversity within the Commonwealth, minimizing the risk and exposure to capacity market pricing volatility, enhancing the reliability and resilience of the Commonwealth's electric system, minimizing emissions of sulfur dioxide, nitrogen oxide, particulate matter, and other pollution that adversely affect public health and the environment in the Commonwealth, and meeting goals to limit carbon dioxide emissions under the laws of the Commonwealth.

E. To enhance reliability and performance of the utility's generation and distribution system, each Phase I and Phase II Utility shall petition the Commission for necessary approvals to construct, acquire, or procure utility-owned energy storage resources. For the purposes of this subsection, "long-duration energy storage" means energy storage resources with 10 hours or more of generation capacity operating at full nameplate capacity and "short-duration energy storage" means energy storage resources with less than 10 hours of generation capacity.

1. By December 31, 2040, each Phase I Utility shall petition the Commission for necessary approvals to construct, acquire, or procure 780 megawatts of short-duration energy storage capacity. Nothing in this subdivision shall prohibit a Phase I Utility from constructing, acquiring, or procuring more than 780 megawatts of short-duration energy storage, provided that the utility receives approval from the Commission pursuant to §§ 56-580 and 56-585.1 . Each Phase I Utility shall petition for at least 10 percent of all short-duration energy storage required by this subdivision to be recovered as electric distribution grid transformation projects in Commission filings conducted pursuant to subdivision A 6 of § 56-585.1 .

2. By December 31, 2045, each Phase II Utility shall petition the Commission for necessary approvals to construct or acquire 16,000 megawatts of short-duration energy storage capacity, including 4,000 megawatts of short-duration energy storage capacity that shall be petitioned for by December 31, 2030. Nothing in this subdivision shall prohibit a Phase II Utility from constructing, acquiring, or procuring more short-duration energy storage than required by this subdivision, provided that the utility receives approval from the Commission pursuant to §§ 56-580 and 56-585.1 . Each Phase II Utility shall petition for at least 10 percent of all short-duration energy storage required by this subdivision to be recovered as electric distribution grid transformation projects in Commission filings conducted pursuant to subdivision A 6 of § 56-585.1 .

3. (Effective pursuant to Acts 2026, cc. 694, 695, cl. 4) By December 31, 2045, each Phase I Utility shall petition the Commission for necessary approvals to construct, acquire, or procure 520 megawatts of long-duration energy storage capacity, half of which shall be petitioned to the Commission for necessary approvals to be constructed, acquired, or procured by December 31, 2035. Of such 520 megawatts, half shall have between 10 and 24 hours of storage capacity and the other half shall have more than 24 hours of storage capacity. Nothing in this subdivision shall prohibit a Phase I Utility from constructing, acquiring, or procuring more than 520 megawatts of long-duration energy storage, provided that the utility receives approval from the Commission pursuant to §§ 56-580 and 56-585.1 .

4. (Effective pursuant to Acts 2026, cc. 694, 695, cl. 4) By December 31, 2045, each Phase II Utility shall petition the Commission for necessary approvals to construct, acquire, or procure 4,000 megawatts of long-duration energy storage capacity, half of which shall be petitioned to the Commission for necessary approvals to be constructed, acquired, or procured by December 31, 2035. Of such 4,000 megawatts, (i) half shall have between 10 and 24 hours of storage capacity and the other half shall have more than 24 hours of storage capacity and (ii) at least 20 percent shall be located in the coalfield region of the Commonwealth, as described in § 15.2-6002 . Nothing in this subdivision shall prohibit a Phase II Utility from constructing, acquiring, or procuring more than 4,000 megawatts of long-duration energy storage, provided that the utility receives approval from the Commission pursuant to §§ 56-580 and 56-585.1 .

5. For all energy storage projects proposed for construction, acquisition, or procurement pursuant to this subsection, the Phase I or Phase II Utility shall demonstrate compliance with the minimum safety standards set forth in the most recently published edition of the National Fire Protection Association 855 Standard for the Installation of Stationary Energy Storage Systems.

6. No single energy storage project shall exceed 500 megawatts in size, except that a Phase II Utility may procure a single energy storage project up to 800 megawatts.

7. All energy storage projects constructed, acquired, or procured pursuant to this subsection shall meet the competitive procurement protocols established in subdivision D 3. For all such energy storage projects, the utility shall demonstrate to the Commission that its procurement sought proposals for both the purchase of storage capacity and the purchase of storage facilities and evaluated the comparative costs, risk allocation, ownership implications, and impact on customers of each proposal received.

8. After July 1, 2020, at least 35 percent of the energy storage facilities placed into service shall be (i) purchased by the public utility from a party other than the public utility or (ii) owned by a party other than a public utility, with the capacity from such facilities sold to the public utility. By January 1, 2027, the Commission shall adopt regulations to achieve the deployment of energy storage for the Commonwealth required in subdivisions 1 and 2, including regulations that set interim targets from 2031 until 2045 and update existing utility planning and procurement rules. The regulations shall include programs and mechanisms to deploy energy storage, including competitive solicitations, behind-the-meter incentives, non-wires alternatives programs, and peak demand reduction programs. The Commission shall update such regulations no less frequently than every five years.

9. If a Phase I or Phase II Utility newly acquires the right, by contract or otherwise, to energy storage capacity from pumped storage facilities located in the Commonwealth, or makes investments to increase the electrical capacity of any such facility, such newly acquired or increased pumped storage capacity shall count toward the requirements of subdivision E 1 or 2 of § 56-585.5 .

F. All costs incurred by a Phase I or Phase II Utility related to compliance with the requirements of this section or pursuant to § 56-585.1:11 , including (i) costs of generation facilities powered by sunlight or onshore or offshore wind, or energy storage facilities, that are constructed or acquired by a Phase I or Phase II Utility after July 1, 2020, (ii) costs of capacity, energy, or environmental attributes from generation facilities powered by sunlight or onshore or offshore wind, or falling water, or energy storage facilities purchased by the utility from persons other than the utility through agreements after July 1, 2020, and (iii) all other costs of compliance, including costs associated with the purchase of RECs associated with RPS Program requirements pursuant to this section shall be recovered from all retail customers in the service territory of a Phase I or Phase II Utility as a non-bypassable charge, irrespective of the generation supplier of such customer, except (a) as provided in subsection G for an accelerated clean energy buyer or (b) as provided in subdivision C 3 of § 56-585.1:11 , with respect to the costs of an offshore wind generation facility, for a PIPP eligible utility customer or an advanced clean energy buyer or qualifying large general service customer, as those terms are defined in § 56-585.1:11 . If a Phase I or Phase II Utility serves customers in more than one jurisdiction, such utility shall recover all of the costs of compliance with the RPS Program requirements from its Virginia customers through the applicable cost recovery mechanism, and all associated energy, capacity, and environmental attributes shall be assigned to Virginia to the extent that such costs are requested but not recovered from any system customers outside the Commonwealth.

By September 1, 2020, the Commission shall direct the initiation of a proceeding for each Phase I and Phase II Utility to review and determine the amount of such costs, net of benefits, that should be allocated to retail customers within the utility's service territory which have elected to receive electric supply service from a supplier of electric energy other than the utility, and shall direct that tariff provisions be implemented to recover those costs from such customers beginning no later than January 1, 2021. Thereafter, such charges and tariff provisions shall be updated and trued up by the utility on an annual basis, subject to continuing review and approval by the Commission.

G. 1. An accelerated clean energy buyer may contract with a Phase I or Phase II Utility, or a person other than a Phase I or Phase II Utility, to obtain (i) RECs from RPS Program eligible resources or (ii) bundled capacity, energy, and RECs from or wind generation resources located within the PJM region and initially placed in commercial operation after January 1, 2015, including any contract with a utility for such generation resources that does not allocate the cost of such resources to or recover the cost of such resources from any other customers of the utility that have not voluntarily agreed to pay such cost. Beginning July 1, 2026, an accelerated clean energy buyer that is a customer of a Phase I or Phase II Utility may also contract with a Phase I or Phase II Utility, or a person other than a Phase I or Phase II Utility, to obtain zero-carbon electricity from generation resources located within the PJM region and initially placed in commercial operation after January 1, 2015, or placed in commercial operation on or before January 1, 2015, if investments to increase the maximum thermal power output of such facility resulted in the generation of new electricity after July 1, 2026, or if a financial agreement for procurement of energy and capacity was entered into with such facility after July 1, 2026, to prevent the previously announced early retirement or decommissioning of such facility due to financial constraints. Such an accelerated clean energy buyer may offset all or a portion of its electric load for purposes of RPS Program compliance through such arrangements. An accelerated clean energy buyer obtaining capacity, energy, or RECs from qualifying solar, wind, or zero-carbon electricity generation resources or energy storage facilities shall be exempt from the assignment of non-bypassable RPS Program compliance costs pursuant to subsection F, with the exception of the costs of an offshore wind generating facility pursuant to § 56-585.1:11 , based on the amount (i) RECs from generation resources located within the PJM region and (ii) zero-carbon electricity from generation resources located within the Commonwealth obtained pursuant to this subsection in proportion to the customer's total electric energy consumption, on an annual basis. An accelerated clean energy buyer obtaining bundled capacity or energy from zero-carbon electricity generation resources located within the PJM region but not located within the Commonwealth shall only be exempt from the assignment of non-bypassable RPS Program compliance costs pursuant to subdivision F that are associated with the purchase of RECs required for RPS Program compliance, based on the amount of zero-carbon electric energy obtained pursuant to this subsection in proportion to the customer's total electric energy consumption, on an annual basis. An accelerated clean energy buyer may also contract with a Phase I or Phase II Utility, or a person other than a Phase I or Phase II Utility, to obtain capacity from energy storage facilities located within the network service area of the utility pursuant to this subsection, provided that the costs of such resources are not recovered from any of the utility's customers who have not voluntarily agreed to pay for such costs. Such accelerated clean energy buyer shall be exempt from the assignment of non-bypassable RPS Program compliance costs specifically associated with energy storage facilities pursuant to this subsection in proportion to the customer's total capacity demand on an annual basis. An accelerated clean energy buyer obtaining RECs only shall not be exempt from costs related to procurement of new solar or onshore wind generation capacity, energy, or environmental attributes, or energy storage facilities, by the utility pursuant to subsections D and E, however, an accelerated clean energy buyer that is a customer of a Phase II Utility and was subscribed, as of March 1, 2020, to a voluntary companion experimental tariff offering of the utility for the purchase of renewable attributes from renewable energy facilities that requires a renewable facilities agreement and the purchase of a minimum of 2,000 renewable attributes annually, shall be exempt from allocation of the net costs related to procurement of new solar or onshore wind generation capacity, energy, or environmental attributes, or energy storage facilities, by the utility pursuant to subsections D and E, based on the amount of RECs associated with the customer's renewable facilities agreements associated with such tariff offering as of that date in proportion to the customer's total electric energy consumption, on an annual basis. To the extent that an accelerated clean energy buyer contracts for the capacity of new solar or wind generation resources or energy storage facilities pursuant to this subsection, the aggregate amount of such nameplate capacity shall be offset from the utility's procurement requirements pursuant to subsection D. All RECs associated with contracts entered into by an accelerated clean energy buyer with the utility, or a person other than the utility, for an RPS Program shall not be credited to the utility's compliance with its RPS Program requirements, and the calculation of the utility's RPS Program requirements shall not include the electric load covered by customers certified as accelerated clean energy buyers.

2. Each Phase I or Phase II Utility shall certify, and verify as necessary, to the Commission that the accelerated clean energy buyer has satisfied the exemption requirements of this subsection for each year, or an accelerated clean energy buyer may choose to certify satisfaction of this exemption by reporting to the Commission individually. The Commission may promulgate such rules and regulations as may be necessary to implement the provisions of this subsection.

3. Provided that no incremental costs associated with any contract between a Phase I or Phase II Utility and an accelerated clean energy buyer is allocated to or recovered from any other customer of the utility, any such contract with an accelerated clean energy buyer that is a jurisdictional customer of the utility shall not be deemed a special rate or contract requiring Commission approval pursuant to § 56-235.2 .

4. The Commission shall ensure that any distribution and transmission costs associated with new energy generation resources procured pursuant to this subsection are justly and reasonably allocated.

H. No customer of a Phase II Utility with a peak demand in excess of 100 megawatts in 2019 that elected pursuant to subdivision A 3 of § 56-577 to purchase electric energy from a competitive service provider prior to April 1, 2019, shall be allocated any non-bypassable charges pursuant to subsection F for such period that the customer is not purchasing electric energy from the utility, and such customer's electric load shall not be included in the utility's RPS Program requirements. No customer of a Phase I Utility that elected pursuant to subdivision A 3 of § 56-577 to purchase electric energy from a competitive service provider prior to February 1, 2019, shall be allocated any non-bypassable charges pursuant to subsection F for such period that the customer is not purchasing electric energy from the utility, and such customer's electric load shall not be included in the utility's RPS Program requirements.

I. In any petition by a Phase I or Phase II Utility for a certificate of public convenience and necessity to construct and operate an electrical generating facility that generates electric energy derived from sunlight submitted pursuant to § 56-580 , such utility shall demonstrate that the proposed facility was subject to competitive procurement or solicitation as set forth in subdivision D 3.

J. Notwithstanding any contrary provision of law, for the purposes of this section, any falling water generation facility located in the Commonwealth and commencing commercial operations prior to July 1, 2024, shall be considered a renewable energy portfolio standard (RPS Program) eligible source.

K. Nothing in this section shall apply to any entity organized under Chapter 9.1 (§ 56-231.15 et seq.).

L. The Commission shall adopt such rules and regulations as may be necessary to implement the provisions of this section, including a requirement that participants verify whether the RPS Program requirements are met in accordance with this section.

2020, cc. 1193 , 1194 ; 2021, Sp. Sess. I, cc. 140 , 328 , 532 ; 2023, cc. 732 , 803 , 804 ; 2024, cc. 596 , 597 ; 2025, cc. 707 , 708 , 713 , 714 ; 2026, cc. 43 , 512 , 645 , 646 , 694 , 695 , 733 , 734 .
Va. Code Ann. § 56-576 — Virginia Code / Title 56 / Chapter 23 / Section 56-576
Definitions
Status: in_force

As used in this chapter:

"Affiliate" means any person that controls, is controlled by, or is under common control with an electric utility.

"Aggregator" means a person that, as an agent or intermediary, (i) offers to purchase, or purchases, electric energy or (ii) offers to arrange for, or arranges for, the purchase of electric energy, for sale to, or on behalf of, two or more retail customers not controlled by or under common control with such person. The following activities shall not, in and of themselves, make a person an aggregator under this chapter: (i) furnishing legal services to two or more retail customers, suppliers or aggregators; (ii) furnishing educational, informational, or analytical services to two or more retail customers, unless direct or indirect compensation for such services is paid by an aggregator or supplier of electric energy; (iii) furnishing educational, informational, or analytical services to two or more suppliers or aggregators; (iv) providing default service under § 56-585 ; (v) engaging in activities of a retail electric energy supplier, licensed pursuant to § 56-587 , which are authorized by such supplier's license; and (vi) engaging in actions of a retail customer, in common with one or more other such retail customers, to issue a request for proposal or to negotiate a purchase of electric energy for consumption by such retail customers.

"Business park" means a land development containing a minimum of 100 contiguous acres classified as a Tier 4 site under the Virginia Economic Development Partnership's Business Ready Sites Program that is developed and constructed by a locality, an industrial development authority, or a similar political subdivision of the Commonwealth created pursuant to § 15.2-4903 or other act of the General Assembly, in order to promote business development.

"Combined heat and power" means a method of using waste heat from electrical generation to offset traditional processes, space heating, air conditioning, or refrigeration.

"Commission" means the State Corporation Commission.

"Community in which a majority of the population are people of color" means a U.S. Census tract where more than 50 percent of the population comprises individuals who identify as belonging to one or more of the following groups: Black, African American, Asian, Pacific Islander, Native American, other non-white race, mixed race, Hispanic, Latino, or linguistically isolated.

"Cooperative" means a utility formed under or subject to Chapter 9.1 (§ 56-231.15 et seq.).

"Covered entity" means a provider in the Commonwealth of an electric service not subject to competition but does not include default service providers.

"Covered transaction" means an acquisition, merger, or consolidation of, or other transaction involving stock, securities, voting interests or assets by which one or more persons obtains control of a covered entity.

"Curtailment" means inducing retail customers to reduce load during times of peak demand so as to ease the burden on the electrical grid.

"Customer choice" means the opportunity for a retail customer in the Commonwealth to purchase electric energy from any supplier licensed and seeking to sell electric energy to that customer.

"Demand response" means measures aimed at shifting time of use of electricity from peak-use periods to times of lower demand by inducing retail customers to curtail electricity usage during periods of congestion and higher prices in the electrical grid.

"Distribute,""distributing," or "distribution of" electric energy means the transfer of electric energy through a retail distribution system to a retail customer.

"Distributor" means a person owning, controlling, or operating a retail distribution system to provide electric energy directly to retail customers.

"Electric distribution grid transformation project" means a project associated with electric distribution infrastructure, including related data analytics equipment, that is designed to accommodate or facilitate the integration of utility-owned or customer-owned renewable electric generation resources with the utility's electric distribution grid or to otherwise enhance electric distribution grid reliability, electric distribution grid security, customer service, or energy efficiency and conservation, including advanced metering infrastructure; intelligent grid devices for real time system and asset information; automated control systems for electric distribution circuits and substations; communications networks for service meters; intelligent grid devices and other distribution equipment; distribution system hardening projects for circuits, other than the conversion of overhead tap lines to underground service, and substations designed to reduce service outages or service restoration times; physical security measures at key distribution substations; cyber security measures; energy storage systems and microgrids that support circuit-level grid stability, power quality, reliability, or resiliency or provide temporary backup energy supply; electrical facilities and infrastructure necessary to support electric vehicle charging systems; LED street light conversions; and new customer information platforms designed to provide improved customer access, greater service options, and expanded access to energy usage information.

"Electric utility" means any person that generates, transmits, or distributes electric energy for use by retail customers in the Commonwealth, including any investor-owned electric utility, cooperative electric utility, or electric utility owned or operated by a municipality.

"Electrification" means measures that (i) electrify space heating, water heating, cooling, drying, cooking, industrial processes, and other building and industrial end uses that would otherwise be served by onsite, nonelectric fuels, provided that the electrification measures reduce site energy consumption; (ii) to the maximum extent practical, seek to combine with federally authorized customer rebates for heat pump technology; and (iii) for those measures that provide measurable and verifiable energy savings to low-income customers or elderly customers, to the maximum extent practical, seek to combine with either contemporaneously installed measures or previously installed measures that are or were provided under federally funded weatherization programs or state-provided, locality-provided, or utility-provided energy efficiency programs.

"Energy efficiency program" means a program that reduces the total amount of energy that is required for the same process or activity implemented after the expiration of capped rates but does not include electrification of any process or activity primarily fueled by natural gas. Energy efficiency programs include equipment, physical, or program change designed to produce measured and verified reductions in the amount of site energy required to perform the same function and produce the same or a similar outcome. Energy efficiency programs may include (i) electrification; (ii) programs that result in improvements in lighting design, heating, ventilation, and air conditioning systems, appliances, building envelopes, and industrial and commercial processes; (iii) measures, such as the installation of advanced meters, implemented or installed by utilities, that reduce fuel use or losses of electricity and otherwise improve internal operating efficiency in generation, transmission, and distribution systems; and (iv) customer engagement programs that result in measurable and verifiable energy savings that lead to efficient use patterns and practices. Energy efficiency programs include demand response, combined heat and power and waste heat recovery, curtailment, or other programs that are designed to reduce site energy consumption so long as they reduce the total amount of site energy that is required for the same process or activity. Utilities shall be authorized to install and operate such advanced metering technology and equipment on a customer's premises; however, nothing in this chapter establishes a requirement that an energy efficiency program be implemented on a customer's premises and be connected to a customer's wiring on the customer's side of the inter-connection without the customer's expressed consent. Electricity consumption increases that result from Commission-approved electrification measures shall not be considered as a reduction in energy savings under the energy savings requirements set forth in subsection B of § 56-596.2 . Utilities may apply verified total site energy reductions that are attributable to Commission-approved electrification measures to the energy savings requirements set forth in subsection B of § 56-596.2 , subject to a conversion of British thermal unit-based energy savings to an equivalent kilowatt-hour-based energy savings, which conversion shall be subject to Commission approval.

"Generate," "generating," or "generation of" electric energy means the production of electric energy.

"Generator" means a person owning, controlling, or operating a facility that produces electric energy for sale.

"Geothermal electric generating resource" means an electric generating unit that is powered by geothermal energy as defined in § 45.2-2000 .

"Geothermal heating and cooling system" means a system that:

1. Exchanges thermal energy from groundwater or a shallow ground source to generate thermal energy through an electric geothermal heat pump or a system of electric geothermal heat pumps interconnected with any geothermal extraction facility that is (i) a closed loop or a series of closed loop systems in which fluid is permanently confined within a pipe or tubing and does not come in contact with the outside environment or (ii) an open loop system in which ground or surface water is circulated in an environmentally safe manner directly into the facility and returned to the same aquifer or surface water source;

2. Meets or exceeds the current federal Energy Star product specification standards;

3. Replaces or displaces less efficient space or water heating systems, regardless of fuel type;

4. Replaces or displaces less efficient space cooling systems; and

5. Does not feed electricity back to the grid, as defined at the level of the geothermal heat pump.

"Historically economically disadvantaged community" means (i) a community in which a majority of the population are people of color or (ii) a low-income geographic area.

"Incremental annual savings" means the total combined kilowatt-hour savings achieved by electric utility energy efficiency and demand response programs and measures in the program year in which they are installed.

"Incumbent electric utility" means each electric utility in the Commonwealth that, prior to July 1, 1999, supplied electric energy to retail customers located in an exclusive service territory established by the Commission.

"Independent system operator" means a person that may receive or has received, by transfer pursuant to this chapter, any ownership or control of, or any responsibility to operate, all or part of the transmission systems in the Commonwealth.

"In the public interest," for purposes of assessing energy efficiency programs prior to the 2029 program year, describes an energy efficiency program if the Commission determines that the net present value of the benefits exceeds the net present value of the costs as determined by not less than any three of the following four tests: (i) the Total Resource Cost Test; (ii) the Utility Cost Test (also referred to as the Program Administrator Test); (iii) the Participant Test; and (iv) the Ratepayer Impact Measure Test. Such determination shall include an analysis of all four tests, and a program or portfolio of programs shall be approved if the net present value of the benefits exceeds the net present value of the costs as determined by not less than any three of the four tests. For programs proposed for the 2029 program year and all subsequent years, the Commission shall establish targets pursuant to subdivision B 4 of § 56-596.2 , and a program shall be approved if the Commission determines it is cost-effective pursuant to applicable Commission regulations and that the net present value of the benefits exceeds the net present value of the costs as determined by the Total Resource Cost Test. 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, including testimony relied upon by the Commission's staff, that has bearing upon the Commission's decision. If the Commission reduces the proposed budget for a program or portfolio of programs, its final order shall include an analysis of the impact such budget reduction has upon the cost-effectiveness of such program or portfolio of programs. An order by the Commission (a) finding that a program or portfolio of programs is not in the public interest or (b) reducing the proposed budget for any program or portfolio of programs shall adhere to existing protocols for extraordinarily sensitive information. In addition, an energy efficiency program may be deemed to be "in the public interest" if the program (1) provides measurable and verifiable energy savings to low-income customers or elderly customers or (2) is a pilot program of limited scope, cost, and duration, that is intended to determine whether a new or substantially revised program or technology would be cost-effective.

"Low-income geographic area" means any locality, or community within a locality, that has a median household income that is not greater than 80 percent of the local median household income, or any area in the Commonwealth designated as a qualified opportunity zone by the U.S. Secretary of the Treasury via his delegation of authority to the Internal Revenue Service.

"Low-income utility customer" means any person or household whose income is no more than 80 percent of the median income of the locality in which the customer resides. The median income of the locality is determined by the U.S. Department of Housing and Urban Development.

"Measured and verified" means a process determined pursuant to methods accepted for use by utilities and industries to measure, verify, and validate energy savings and peak demand savings. This may include the protocol established by the United States Department of Energy, Office of Federal Energy Management Programs, Measurement and Verification Guidance for Federal Energy Projects, measurement and verification standards developed by the American Society of Heating, Refrigeration and Air Conditioning Engineers (ASHRAE), or engineering-based estimates of energy and demand savings associated with specific energy efficiency measures, as determined by the Commission.

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

"New underground facilities" means facilities to provide underground distribution service. "New underground facilities" includes underground cables with voltages of 69 kilovolts or less, pad-mounted devices, connections at customer meters, and transition terminations from existing overhead distribution sources.

"Peak-shaving" means measures aimed solely at shifting time of use of electricity from peak-use periods to times of lower demand by inducing retail customers to curtail electricity usage during periods of congestion and higher prices in the electrical grid.

"Percentage of Income Payment Program (PIPP) eligible utility customer" means any person or household whose income does not exceed 150 percent of the federal poverty level.

"Person" means any individual, corporation, partnership, association, company, business, trust, joint venture, or other private legal entity, and the Commonwealth or any municipality.

"Previously developed project site" means any property, including related buffer areas, if any, that has been previously disturbed or developed for non-single-family residential, non-agricultural, or non-silvicultural use, regardless of whether such property currently is being used for any purpose.

"Previously developed project site" includes a brownfield as defined in § 10.1-1230 or any parcel that has been previously used (i) for a retail, commercial, or industrial purpose; (ii) as a parking lot; (iii) as the site of a parking lot canopy or structure; (iv) for mining, which is any lands affected by coal mining that took place before August 3, 1977, or any lands upon which extraction activities have been permitted by the Department of Energy under Title 45.2; (v) for quarrying; or (vi) as a landfill.

"Qualified waste heat resource" means (i) exhaust heat or flared gas from an industrial process that does not have, as its primary purpose, the production of electricity and (ii) a pressure drop in any gas for an industrial or commercial process.

"Renewable energy" means energy derived from sunlight, wind, falling water, biomass, sustainable or otherwise, (the definitions of which shall be liberally construed), energy from waste, landfill gas, municipal solid waste, wave motion, tides, geothermal heating and cooling systems, and geothermal electric generating resources and does not include energy derived from coal, oil, natural gas, or nuclear power. "Renewable energy" also includes the proportion of the thermal or electric energy from a facility that results from the co-firing of biomass. "Renewable energy" does not include waste heat from fossil-fired facilities or electricity generated from pumped storage but includes run-of-river generation from a combined pumped-storage and run-of-river facility.

"Renewable thermal energy" means the thermal energy output from (i) a renewable-fueled combined heat and power generation facility that is (a) constructed, or renovated and improved, after January 1, 2012, (b) located in the Commonwealth, and (c) utilized in industrial processes other than the combined heat and power generation facility or (ii) a solar energy system, certified to the OG-100 standard of the Solar Ratings and Certification Corporation or an equivalent certification body, that (a) is constructed, or renovated and improved, after January 1, 2013, (b) is located in the Commonwealth, and (c) heats water or air for residential, commercial, institutional, or industrial purposes.

"Renewable thermal energy equivalent" means the electrical equivalent in megawatt hours of renewable thermal energy calculated by dividing (i) the heat content, measured in British thermal units (BTUs), of the renewable thermal energy at the point of transfer to a residential, commercial, institutional, or industrial process by (ii) the standard conversion factor of 3.413 million BTUs per megawatt hour.

"Renovated and improved facility" means a facility the components of which have been upgraded to enhance its operating efficiency.

"Retail customer" means any person that purchases retail electric energy for its own consumption at one or more metering points or nonmetered points of delivery located in the Commonwealth.

"Retail electric energy" means electric energy sold for ultimate consumption to a retail customer.

"Revenue reductions related to energy efficiency programs" means reductions in the collection of total non-fuel revenues, previously authorized by the Commission to be recovered from customers by a utility, that occur due to measured and verified decreased consumption of electricity caused by energy efficiency programs approved by the Commission and implemented by the utility, less the amount by which such non-fuel reductions in total revenues have been mitigated through other program-related factors, including reductions in variable operating expenses.

"Rooftop solar installation" means a distributed electric generation facility, storage facility, or generation and storage facility utilizing energy derived from sunlight, with a rated capacity of not less than 50 kilowatts, that is installed on the roof structure of an incumbent electric utility's commercial or industrial class customer, including host sites on commercial buildings, multifamily residential buildings, school or university buildings, and buildings of a church or religious body.

"Solar energy system" means a system of components that produces heat or electricity, or both, from sunlight.

"Supplier" means any generator, distributor, aggregator, broker, marketer, or other person who offers to sell or sells electric energy to retail customers and is licensed by the Commission to do so, but it does not mean a generator that produces electric energy exclusively for its own consumption or the consumption of an affiliate.

"Supply" or "supplying" electric energy means the sale of or the offer to sell electric energy to a retail customer.

"Total annual energy savings" means (i) the total combined kilowatt-hour savings achieved by electric utility energy efficiency and demand response programs and measures installed in that program year, as well as savings still being achieved by measures and programs implemented in prior years, or (ii) savings attributable to newly installed combined heat and power facilities, including waste heat-to-power facilities, and any associated reduction in transmission line losses, provided that biomass is not a fuel and the total efficiency, including the use of thermal energy, for eligible combined heat and power facilitates must meet or exceed 65 percent and have a nameplate capacity rating of less than 25 megawatts.

"Transmission of,""transmit," or "transmitting" electric energy means the transfer of electric energy through the Commonwealth's interconnected transmission grid from a generator to either a distributor or a retail customer.

"Transmission system" means those facilities and equipment that are required to provide for the transmission of electric energy.

"Waste heat to power" means a system that generates electricity through the recovery of a qualified waste heat resource.

1999, c. 411 ; 2000, c. 991 ; 2001, c. 421 ; 2007, cc. 888 , 933 ; 2008, cc. 272 , 883 ; 2009, cc. 748 , 824 ; 2012, cc. 46 , 200 , 210 , 821 ; 2013, c. 494 ; 2014, cc. 212 , 548 ; 2018, c. 296 ; 2019, cc. 535 , 741 ; 2020, cc. 1193 , 1194 , 1225 ; 2021, Sp. Sess. I, cc. 308 , 532 ; 2022, c. 216 ; 2024, cc. 597 , 607 , 794 , 818 ; 2025, c. 714 ; 2026, cc. 733 , 734 .
Va. Code Ann. § 56-527 — Virginia Code / Title 56 / Chapter 17 / Section 56-527
Chapter not applicable to certain carriers
Status: in_force

With the exception of ferries nothing in this chapter shall apply to any express company, sleeping car company, common carrier engaged in interstate commerce by railroad or by air or to any company which is directly or indirectly owned or controlled by any carrier by railroad.

1952, c. 696; 1954, c. 108.
Va. Code Ann. § 56-366.1 — Virginia Code / Title 56 / Chapter 13 / Article 3 / Section 56-366.1
Proceedings to avoid or eliminate grade crossings by grade separation or to widen, strengthen, remodel, relocate or replace existing crossing structures on public highways
Status: in_force

Whenever a road in the primary or secondary state highway system or a public highway maintained by a locality (i) crosses a railroad, (ii) is projected across a railroad, or (iii) is to be so changed as to cross a railroad, or an existing overpass or underpass crossing of any such road and a railroad is in need of widening, strengthening, remodeling, relocating or replacing, and funds are (or are to be) allocated by the Commonwealth Transportation Board or public road authority for payment of the locality's or state's portion of the cost of constructing such an overpass or underpass structure or for widening, strengthening, remodeling, relocating or replacing such an existing structure, the Commissioner of Highways or representative of the public road authority may agree with the railroad company or companies involved, on such terms and conditions as he shall deem in the best interests of the Commonwealth or locality regarding the plans and specifications, the method and manner of construction and the division of costs and maintenance responsibility of any such separation of grade structure. In case of a separation of grade by structure at a new, or an existing, grade crossing, the project, except in special cases and under special circumstances to be mutually agreed upon by the Commissioner of Highways, the public road authority, and the railroad company or companies involved, shall be deemed to start at points on each side of the tracks of the railroad or railroads where the grade, under the proposed plans and specifications, leaves the ground line to go over or under, as the case may be, the tracks of the railroad or railroads.

In the event the Commissioner of Highways, the public road authority, and the railroad company or companies involved are unable to agree on (i) the necessity for the construction of such underpass or overpass structure or for the widening, strengthening, remodeling, relocating or replacing of any existing overpass or underpass structure, (ii) the plans and specifications for and method or manner of construction thereof, or (iii) the portion of the work, if any, to be done and the share of the cost of such project, if any, to be borne by each of the railroad company or companies involved, the Commissioner of Highways or the public road authority shall petition the State Corporation Commission setting forth the plans and specifications for and the method and manner of construction of such project and the facts which in his opinion justify the elimination of the crossing, the erection of a new separation of grade structure or the widening, strengthening, remodeling, relocating or replacing of an existing structure and the maintenance responsibility. Copies of the petition and the plans and specifications shall forthwith be served by the State Corporation Commission on the railroad company or companies involved. Within twenty days after service on it of such petition and plans and specifications, the railroad company or companies shall file an answer with the State Corporation Commission setting out its objections to the proposed project and the Commission shall hear and determine the matter as other matters are heard and determined by that body. The Commission shall consider all the facts and circumstances surrounding the case and shall determine (a) whether public necessity and convenience justifies or requires the construction of such new separation of grade structure or whether an existing structure is so dangerous to or insufficient to take care of traffic on the highway as to require the widening, strengthening, remodeling, relocating or replacing proposed, (b) whether the plans and specifications or method and manner of construction are proper and appropriate, and (c) what portion of the work, if any, to be done and what share of the cost of such project, if any, to be borne by each of the railroad company or companies involved (excluding the cost of right-of-way) is fair and reasonable, having regard to the benefits, if any, accruing to such railroad or railroads from the elimination of such grade crossing or the widening, strengthening, remodeling, relocating or replacing any existing overpass or underpass structure, and either dismiss the proceeding as against the railroad company or companies involved or enter an order deciding and disposing of all of the matters hereinbefore submitted to its jurisdiction.

Grade crossings shall be closed when replaced by a new public highway. However, the Commonwealth Transportation Board or the public road authority may authorize the continued use of the crossing for a period of two years following the construction of the new highway to familiarize the public with the new route.

1952, c. 398; 1996, cc. 114 , 157 ; 2015, c. 256 .
Va. Code Ann. § 56-547 — Virginia Code / Title 56 / Chapter 20 / Section 56-547
Utility crossings
Status: in_force

The applicant shall include in the application a list of public utility facilities and rights-of-way to be crossed or otherwise affected in the construction of the roadway and a plan and schedule for such crossings. The operator and each public utility whose works are to be crossed or affected shall each have the duty to cooperate fully with the other in planning and arranging of the manner of the crossing or relocation of the facilities. Any public service corporation possessing the powers of eminent domain is hereby expressly granted such powers in connection with the moving or relocation of facilities to be crossed by the roadway or which must be relocated to the extent that such moving or relocation is made necessary by construction of the roadway, which shall be construed to include construction of temporary facilities for the purpose of providing service during the period of construction. Should the applicant or operator and the public utility whose facilities are to be crossed or relocated not be able to agree upon a plan for such crossing or any necessary relocation, either party may request the Commission to inquire into the need for the crossing or relocation and to decide whether such crossing or relocation should be compelled, and if so, the manner in which such crossing or relocation is to be accomplished and any damages due either party arising out of the crossing or relocation. The Commission may in its discretion employ expert engineers who shall examine the location and plans for such crossing or relocation, hear any objections and consider modifications, and make a recommendation to the Commission. In such a case, the cost of the experts is to be borne equally by the applicant and the public utility, unless the Commission determines that it would be unjust, in which case the cost shall be borne as the Commission decides. Railroads shall be included within the scope of the term "public utility" for purposes of this section.

1988, c. 649.
Va. Code Ann. § 56-235.5:1 — Virginia Code / Title 56 / Chapter 10 / Article 2 / Section 56-235.5:1
Local exchange telephone service competition policy
Status: in_force

A. The Commission, in resolving issues and cases concerning local exchange telephone service under the federal Telecommunications Act of 1996 (P.L. 104-104), this title, or both, shall, consistent with federal and state laws, consider it in the public interest to, as appropriate, (i) treat all providers of local exchange telephone services in an equitable fashion and without undue discrimination and, to the greatest extent possible, apply the same rules to all providers of local exchange telephone services; (ii) promote competitive product offerings, investments, and innovations from all providers of local exchange telephone services in all areas of the Commonwealth; and (iii) reduce or eliminate any requirement to price retail and wholesale products and services at levels that do not permit providers of local exchange telephone services to recover their costs of those products and services.

B. In order to treat all providers of local exchange telephone service more equitably and without undue discrimination by ensuring that they are subject to the same rules:

1. Notwithstanding any other provision of law, the Commission shall (i) for incumbent local exchange carriers serving more than 15,000 access lines in its incumbent territory, establish a schedule that eliminates the carrier common line charge element of intrastate carrier switched access charges no later than July 1, 2013, provided that (a) any such carrier that directly receives no later than April 1, 2010, a Broadband Initiatives Program grant and loan for use in the Commonwealth from the Rural Utilities Service of the U.S. Department of Agriculture under the American Recovery and Reinvestment Act of 2009 (P.L. 111-5) shall be considered under clause (ii), and (b) any such carrier that has not been the subject of a Commission proceeding to investigate its carrier common line charge may apply to the Commission for an opportunity to be heard as to why it is in the public interest and why it will not unreasonably prejudice or disadvantage telephone customers throughout the Commonwealth to extend the deadline for the elimination of its carrier common line charge to a date determined by the Commission, but in no case later than July 1, 2014; and (ii) for incumbent local exchange carriers with 15,000 or fewer access lines in its incumbent territory, determine, no later than July 1, 2011, and after notice and an opportunity for a hearing, a schedule for the elimination of the carrier common line charge element of intrastate carrier switched access charges in a manner to be determined by the Commission.

2. The Commission shall permit any incumbent local exchange carrier to increase its retail rates to recover a reasonable amount of carrier common line charge revenue lost due to the reductions required in subdivision 1.

2004, c. 151 ; 2010, c. 748 ; 2013, c. 26 .
Va. Code Ann. § 56-235.9 — Virginia Code / Title 56 / Chapter 10 / Article 2 / Section 56-235.9
Recovery of funds used for capital projects prior to a rate case for strategic natural gas facilities
Status: in_force

A. As used in this section:

"Capitalized carrying cost" includes the return on the investment, depreciation, and tax.

"Natural gas transmission company" means any investor-owned public service company engaged in the business of transporting natural gas to more than one electric utility, natural gas utility, or non-jurisdictional customer.

"Natural gas utility" means any investor-owned public service company engaged in the business of furnishing natural gas service to the public.

"Strategic natural gas facility" includes, without limitation, a natural gas distribution or transmission pipeline, storage facility, compressor station, liquefied natural gas facility, peaking facility or other appurtenant facility, used to furnish natural gas service in the Commonwealth that, for a natural gas utility with fewer than 150,000 customers, adds stand-alone design day deliverability or designed send-out of at least 10,000 dekaTherms per day or two or more such facilities, regardless of size, that add design day deliverability or designed send out of at least 75,000 dekaTherms per day in the aggregate, and for a natural gas utility with 150,000 or more customers, adds stand-alone design day deliverability or designed send out of at least 20,000 dekaTherms per day or two or more such facilities, regardless of size, that add design day deliverability or designed send out of at least 100,000 dekaTherms per day in the aggregate, and for a natural gas transmission company, adds design day deliverability or designed send out of at least 100,000 dekaTherms per day in the aggregate.

B. Any natural gas utility that places a strategic natural gas facility into service on or after July 1, 2008, or natural gas transmission company that places a strategic natural gas facility into service on or after July 1, 2014, to serve its customers shall have the right to recover through its rates charged to those customers the entire prudently incurred costs of the facility including: planning, development and construction costs; costs of infrastructure associated therewith; an allowance for funds used during construction; and the capitalized carrying cost from the time construction is completed and the asset is placed into service until the time that the Commission establishes new rates that include recovery of all costs as defined herein. Such recovery shall be permitted by allowing such costs to be recorded in the utility's plant accounts and included in rate base for purposes of cost recovery (i) in new rate schedules for service not offered under existing rate schedules or new rate schedules for expansion of existing services as permitted by § 56-235.4 , (ii) in a rate case using the cost of service methodology set forth in § 56-235.2 , or (iii) in a performance-based regulation plan authorized by § 56-235.6 , subject to Commission determination that such costs were prudently incurred. The allowance for funds used during construction and the return on investment shall be calculated utilizing the weighted average cost of capital, including the cost of debt and cost of equity used in determining the natural gas utility's base rates in effect during the construction period of the strategic natural gas facility.

C. Nothing in this section shall be construed to prohibit the Commission from granting similar treatment to other natural gas facilities when the Commission deems such treatment to be in the public interest.

2008, c. 867 ; 2014, cc. 467 , 507 .
Va. Code Ann. § 56-457 — Virginia Code / Title 56 / Chapter 14 / Section 56-457
Repealed
Status: repealed

Repealed by Acts 1971, Ex. Sess., c. 25.
Va. Code Ann. § 56-524 — Virginia Code / Title 56 / Chapter 17 / Section 56-524
Penalties
Status: in_force

Any person violating any of the provisions of §§ 56-512 , 56-515 or § 56-517 shall be guilty of a misdemeanor and upon conviction of same shall be fined not less than $10 nor more than $1,000, and may be imprisoned in jail for not more than 12 months.

1952, c. 696.
Va. Code Ann. § 56-594.3 — Virginia Code / Title 56 / Chapter 23 / Section 56-594.3
Shared solar programs; Phase II Utility
Status: in_force

A. As used in this section:

"Administrative cost" means the reasonable incremental cost to the investor-owned utility to process subscribers' bills for the program.

"Applicable bill credit rate" means the dollar-per-kilowatt-hour rate used to calculate the subscriber's bill credit.

"Bill credit" means the monetary value of the electricity, in kilowatt-hours, generated by the shared solar facility allocated to a subscriber to offset that subscriber's electricity bill.

"Dual-use agricultural facility" means agricultural production and electricity production from solar photovoltaic panels occurring simultaneously on the same property.

"Gross bill" means the amount that a customer would pay to the utility based on the customer's monthly energy consumption before any bill credits are applied.

"Incremental cost" means any cost directly caused by the implementation of the shared solar program that would not have occurred absent the implementation of the shared solar program.

"Low-income customer" means any person or household whose income is no more than 80 percent of the median income of the locality in which the customer resides. The median income of the locality is determined by the U.S. Department of Housing and Urban Development.

"Low-income service organization" means a nonresidential customer of an investor-owned utility whose primary purpose is to serve low-income individuals and households.

"Low-income shared solar facility" means a shared solar facility at least 30 percent of the capacity of which is subscribed by low-income customers or low-income service organizations.

"Minimum bill" means an amount determined by the Commission under subsection D that a subscriber is required to, at a minimum, pay on the subscriber's utility bill each month after accounting for any bill credits.

"Net bill" means the resulting amount a customer must pay the utility after deducting the bill credit from the customer's monthly gross bill.

"Phase II Utility" has the same meaning as provided in subdivision A 1 of § 56-585.1 .

"Shared solar facility" means a facility that:

1. Generates electricity by means of a solar photovoltaic device with a nameplate capacity rating that does not exceed 5,000 kilowatts of alternating current;

2. Is interconnected with a Phase II Utility's distribution system within the Commonwealth;

3. Has at least three subscribers;

4. Has at least 40 percent of its capacity subscribed by customers with subscriptions of 25 kilowatts or less; and

5. Is located on a single parcel of land.

"Shared solar program" or "program" means the program created through the adoption of rules to allow for the development of shared solar facilities.

"Subscriber" means a retail customer of a utility that (i) owns one or more subscriptions of a shared solar facility that is interconnected with the utility and (ii) receives service in the service territory of the same utility in whose service territory the shared solar facility is interconnected.

"Subscriber organization" means any for-profit or nonprofit entity that owns or operates one or more shared solar facilities. A subscriber organization shall not be considered a utility solely as a result of its ownership or operation of a shared solar facility. A subscriber organization licensed with the Commission shall be eligible to own or operate shared solar facilities in more than one investor-owned utility service territory.

"Subscribed" means, in relation to a subscription, that a subscriber has made initial payments or provided a deposit to the owner of a shared solar facility for such subscription.

"Subscription" means a contract or other agreement between a subscriber and the owner of a shared solar facility. A subscription shall be sized such that the estimated bill credits do not exceed the subscriber's average annual bill for the customer account to which the subscription is attributed.

"Utility" means a Phase II Utility.

B. The Commission shall establish by regulation a program that affords customers of a Phase II Utility the opportunity to participate in shared solar projects. Under its shared solar program, the utility shall provide a bill credit for the proportional output of a shared solar facility attributable to that subscriber. The shared solar program shall be administered as follows:

1. The value of the bill credit for the subscriber shall be calculated by multiplying the subscriber's portion of the kilowatt-hour electricity production from the shared solar facility by the applicable bill credit rate for the subscriber. Any amount of the bill credit that exceeds the subscriber's monthly bill, minus the minimum bill, shall be carried over and applied to the next month's bill.

2. The utility shall provide bill credits to a shared solar facility's subscribers for not less than 25 years from the date the shared solar facility becomes commercially operational.

3. The subscriber organization shall, on a monthly basis and in a standardized electronic format, and pursuant to guidelines established by the Commission, provide to the utility a subscriber list indicating the kilowatt-hours of generation attributable to each of the subscribers participating in a shared solar facility in accordance with the subscriber's portion of the output of the shared solar facility.

4. Subscriber lists may be updated monthly to reflect canceling subscribers and to add new subscribers. The utility shall apply bill credits to subscriber bills within two billing cycles following the cycle during which the energy was generated by the shared solar facility.

5. Each utility shall, on a monthly basis and in a standardized electronic format, provide to the subscriber organization a report indicating the total value of bill credits generated by the shared solar facility in the prior month, as well as the amount of the bill credit applied to each subscriber.

6. A subscriber organization may accumulate bill credits in the event that all of the electricity generated by a shared solar facility is not allocated to subscribers in a given month. Pursuant to guidelines established by the Commission, the subscriber organization shall furnish to the utility allocation instructions for distributing excess bill credits to subscribers. A subscriber organization may elect to distribute excess bill credits more frequently than once per year.

7. A subscriber organization that registers a shared solar facility in the program within the first 200 megawatts alternating current of awarded capacity shall own all environmental attributes associated with a shared solar facility, including renewable energy certificates. At such subscriber organization's direction, such environmental attributes may be distributed to subscribers, sold to load-serving entities with compliance obligations or other buyers, accumulated, or retired. For a shared solar facility registered in the program after the first 200 megawatts alternating current of awarded capacity, the registering subscriber organization shall transfer renewable energy certificates to a Phase II Utility to be retired for compliance with such Phase II Utility's renewable portfolio standard obligations pursuant to subsection C of § 56-585.5 .

8. Projects shall be entitled to receive incentives when they are located on rooftops, brownfields, or landfills, are dual-use agricultural facilities, or meet the definition of another category established by the Department of Energy pursuant to this section.

C. Each subscriber shall pay a minimum bill, established pursuant to subsection D, and shall receive an applicable bill credit based on the subscriber's customer class of residential, commercial, or industrial. Each class's applicable credit rate shall be calculated by the Commission annually by dividing revenues to the class by sales, measured in kilowatt-hours, to that class to yield a bill credit rate for the class ($/kWh).

D. The Commission shall establish a minimum bill, which shall include the costs of all utility infrastructure and services used to provide electric service and administrative costs of the shared solar program. The Commission may modify the minimum bill over time. In establishing the minimum bill, the Commission shall (i) consider further costs the Commission deems relevant to ensure subscribing customers pay a fair share of the costs of providing electric services and generation sufficient to meet customer needs at all times, (ii) minimize the costs shifted to customers not in a shared solar program, and (iii) calculate the benefits of shared solar to the electric grid and to the Commonwealth and deduct such benefits from other costs. The Commission shall explicitly set forth its findings as to each cost and benefit, or other value used to determine such minimum bill. Low-income customers shall be exempt from the minimum bill.

E. The Commission shall approve part one of a shared solar program with an aggregate capacity of 200 megawatts. Upon the earlier of (i) a determination that at least 90 percent of the megawatts of the aggregate capacity of such program have been subscribed and that project construction is substantially complete or (ii) July 1, 2026, the Phase II Utility shall release an additional 525 megawatts of capacity as part two of such program, 450 megawatts of which shall serve no more than 51 percent low-income customers and 75 megawatts of which may serve more than 51 percent low-income customers. On or before the substantial completion of 268 megawatts of capacity under part two of such program, the Phase II Utility shall petition the Commission to initiate a shared solar expansion proceeding to determine the capacity for part three of the shared solar program. Subscriber organizations shall be allowed to demonstrate compliance with the low income requirement using either project capacity or project savings methodology. The Commission, in collaboration with the Department of Energy, may adopt mechanisms to ensure low-income customer participation. For the purposes of this subsection, "substantial completion" has the same meaning as provided in Commission regulations for shared solar programs.

F. The Commission shall establish by regulation a shared solar program that complies with the provisions of subsections B, C, D, and E by March 1, 2025, and shall require each utility to file any tariffs, agreements, or forms necessary for implementation of the program by December 1, 2025. Any tariffs, agreements, and forms currently in effect at the time of enactment shall remain in effect until such revisions are approved by the Commission. Any rule or utility implementation filings approved by the Commission shall:

1. Reasonably allow for the creation of shared solar facilities;

2. Allow all customer classes to participate in the program;

3. Create a stakeholder working group including low-income community representatives and community solar providers to facilitate low-income customer and low-income service organization participation in the program;

4. Encourage public-private partnerships to further the Commonwealth's clean energy and equity goals, such as state agency and affordable housing provider participation as subscribers of a shared solar program;

5. Not remove a customer from its otherwise applicable customer class in order to participate in a shared solar facility;

6. Reasonably allow for the transferability and portability of subscriptions, including allowing a subscriber to retain a subscription to a shared solar facility if the subscriber moves within the same utility's service territory;

7. Establish standards, fees, and processes for the interconnection of shared solar facilities that allow the utility to recover reasonable interconnection costs for each shared solar facility;

8. Adopt standardized consumer disclosure forms;

9. Allow the utility the opportunity to recover reasonable costs of administering the program;

10. Ensure nondiscriminatory and efficient requirements and utility procedures for interconnecting projects;

11. Address the co-location of two or more shared solar facilities on a single parcel of land and provide guidelines for determining when two or more such facilities are co-located;

12. Include a program implementation schedule;

13. Prohibit credit checks as a means of establishing eligibility for residential customers to become subscribers;

14. Prohibit early termination fees and credit reporting for any low-income customer;

15. Require a customer's affirmative consent by written or electronic signature before providing access to customer billing and usage data to a subscriber organization;

16. Establish customer engagement rules and minimum rules for education, contract reviews, and continued engagement;

17. Require net crediting functionality. Under net crediting, the utility shall include the shared solar subscription fee on the customer's utility bill and provide the customer with a net credit equivalent to the total bill credit value for that generation period minus the shared solar subscription fee as set by the subscriber organization. The net crediting fee shall not exceed one percent of the bill credit value. Net crediting shall be optional for subscriber organizations, and any shared solar subscription fees charged via the net crediting model shall be set to ensure that subscribers do not pay more in subscription fees than they receive in bill credits; and

18. Allow the utility to recover as the cost of purchased power pursuant to § 56-249.6 any difference between the bill credit provided to the subscriber and the cost of energy injected into the grid by the subscriber organization.

G. In conducting the proceeding for part three of shared solar program capacity under subsection E, the Commission shall evaluate the costs and benefits of the shared solar program, including the aggregate impact of the shared solar program on the Phase II Utility's long-term marginal costs for generation, distribution, and transmission services; the impact of the shared solar program on compliance with renewable energy portfolio standard requirements under § 56-585.5 ; the direct and indirect economic impacts of the shared solar program on the Commonwealth; and any other information deemed relevant by the Commission, including environmental, resilience, fuel price risk, and other risk minimization benefits of the shared solar program. The Commission shall consider the results of such proceeding in determining any future allocations of shared solar capacity and changes in program design.

2020, cc. 1238 , 1264 ; 2021, Sp. Sess. I, c. 532 ; 2024, cc. 715 , 763 ; 2026, cc. 670 , 671 .
Va. Code Ann. § 56-505 — Virginia Code / Title 56 / Chapter 16 / Section 56-505
Charter fees
Status: in_force

The general laws of Virginia relating to fees and other charges in connection with issuing charters, amendments thereto, consolidations and dissolutions of corporations organized on a mutual basis or without capital stock, shall apply to cooperatives organized under the provisions of this chapter.

1950, p. 595; 1956, c. 434.
Va. Code Ann. § 56-67 — Virginia Code / Title 56 / Chapter 3 / Section 56-67
Issuance of securities or assumption of liability void if order not obtained
Status: in_force

Any stock, or stock certificate or other evidence of interest or ownership, and, except as otherwise provided by § 56-65 , any bond, note or other evidence of indebtedness, of a public service company, and every assumption of obligation or liability as a guarantor, endorser, surety or otherwise in respect to the securities of any other person, firm, association or corporation, when such securities are payable at periods of twelve months, or more, after the date thereof, shall be void if issued or assumed without an order of the Commission authorizing the same, or if issued or assumed contrary in any substantial respect to any term or condition of such order as issued, or as modified prior to such issuance or assumption; but no such issuance or assumption, if made in accordance in every substantial respect with all terms and conditions of such order as issued or as modified prior to such issuance or assumption, shall be rendered void because of failure to comply with any provision of this chapter relating to procedure or other matters preceding the entry of such order.

1934, p. 224; Michie Code 1942, § 4073(10).
Va. Code Ann. § 56-484.16:1 — Virginia Code / Title 56 / Chapter 15 / Article 7 / Section 56-484.16:1
PSAP dispatchers; training requirements
Status: in_force

A. As used in this section:

"Dispatcher" means an individual employed by a public safety answering point, an emergency medical dispatch service provider, or both, who is qualified to answer incoming emergency telephone calls or provide for the appropriate emergency response either directly or through communication with the appropriate PSAP.

"Emergency Medical Dispatch" means a systematic program of handling medical calls pursuant to which trained dispatchers determine the nature and priority of the call, dispatch the appropriate response, and give the caller instructions to help treat the caller until the arrival of the appropriate responder.

"Emergency Medical Dispatch certification" means certification by an Office of Emergency Medical Services recognized emergency dispatch training organization meeting or exceeding standards by the National Highway Traffic Safety Administration and accepted and recognized by the American Society for Testing Materials (ASTM).

"Emergency Medical Dispatch education program" means an Emergency Medical Dispatch certification education program that meets national criteria set forth by the National Highway Traffic Safety Administration.

"High-quality telecommunicator cardiopulmonary resuscitation instruction" or "TCPR" means the delivery by trained 911 telecommunicators of high-quality cardiopulmonary resuscitation instruction for acute events requiring cardiopulmonary resuscitation, including out-of-hospital cardiac arrests.

"Office" means the Office of Emergency Medical Services within the Department of Health.

B. By July 1, 2021, the Office of Emergency Medical Services shall adopt standards for training and equipment required for the provision of TCPR by dispatchers. The standards shall meet or exceed nationally recognized emergency cardiovascular care guidelines. At a minimum, training standards shall require dispatchers to obtain certification in cardiopulmonary resuscitation and shall incorporate recognition protocols for out-of-hospital cardiac arrest, compression-only cardiopulmonary resuscitation instructions for callers, and continuing education as appropriate. The Office shall update such standards as frequently as necessary, but not more frequently than biennially, in order to keep the standards current with nationally recognized emergency cardiovascular care guidelines.

C. On or before January 1, 2022, each PSAP shall provide training in TCPR to each dispatcher in its employ and shall provide its dispatchers with equipment necessary for the provision of TCPR. The training and equipment shall comply with the standards adopted by the Office pursuant to subsection B. Following completion of the initial training, each dispatcher's training shall be updated or supplemented in order to reflect updates to the training standards.

D. An operator of a PSAP may enter into a reciprocal agreement with the operator of another PSAP authorizing the initial PSAP to transfer callers to the other PSAP at times that the PSAP does not have a trained dispatcher on duty who is able to provide TCPR to a caller. If a PSAP transfers a caller under the provisions of this subsection, the transferring PSAP shall use an evidence-based protocol for the identification of a person in need of cardiopulmonary resuscitation and ensure that the PSAP to which calls are transferred uses dispatchers who meet the training requirements under subsection B to provide assistance on administering TCPR.

E. The Office of Emergency Medical Services shall identify all public agencies and other persons that provide TCPR training that satisfies the requirements adopted under subsection B and set minimum standards for course approval, instruction, and examination, including online training modules based on nationally recognized guidelines. The Office shall implement a means to ensure that every dispatcher who has satisfactorily completed a training program and his employing PSAP receive a certificate of completion of the required TCPR training.

F. No dispatcher who instructs a caller on TCPR shall be liable for any civil damages arising out of the instruction provided to the caller, except for acts or omissions intentionally designed to harm or for grossly negligent acts or omissions that result in harm to an individual. A caller may decline to receive TCPR. When a caller declines TCPR, the dispatcher has no obligation to provide such instruction.

G. By January 1, 2024, each operator of a PSAP shall implement a requirement that each of its dispatchers shall by July 1, 2024, have completed an Emergency Medical Dispatch education program that complies with minimum standards established by the Office of Emergency Medical Services. The Office shall ensure that every dispatcher who has satisfactorily completed an Emergency Medical Dispatch education program and his employing PSAP receive a certificate of completion of the required education program. Following completion of the initial Emergency Medical Dispatch education program, each dispatcher's training shall be updated or supplemented in order to reflect updates to the education program.

H. Each PSAP shall conduct ongoing quality assurance of its TCPR program.

I. The State Board of Health shall adopt regulations in accordance with the provisions of the Administrative Process Act (§ 2.2-4000 et seq.) as are necessary to implement the provisions of this section.

2020, cc. 1068 , 1069 .