Title 56. Public Service Companies
Subtitle .
Chapter 23. Virginia Electric Utility Regulation Act
Chapter 23. Virginia Electric Utility Regulation Act.
§ 56-576. (Effective until January 1, 2025) Definitions.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.
"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, and geothermal power, 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. 607, 794, 818.
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 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 that do not meet federal Energy Star product specification standards; and
5. Does not feed electricity back to the grid.
"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 power 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.
A. Retail competition for the purchase and sale of electric energy shall be subject to the following provisions:
1. Each incumbent electric utility owning, operating, controlling, or having an entitlement to transmission capacity shall join or establish a regional transmission entity, which entity may be an independent system operator, to which such utility shall transfer the management and control of its transmission system, subject to the provisions of § 56-579.
2. The generation of electric energy shall be subject to regulation as specified in this chapter.
3. Subject to the provisions of subdivisions 4 and 5, only individual retail customers of electric energy within the Commonwealth, regardless of customer class, whose demand during the most recent calendar year exceeded five megawatts but did not exceed one percent of the customer's incumbent electric utility's peak load during the most recent calendar year unless such customer had noncoincident peak demand in excess of 90 megawatts in calendar year 2006 or any year thereafter, shall be permitted to purchase electric energy from any supplier of electric energy licensed to sell retail electric energy within the Commonwealth, except for any incumbent electric utility other than the incumbent electric utility serving the exclusive service territory in which such a customer is located, subject to the following conditions:
a. If such customer does not purchase electric energy from licensed suppliers, such customer shall purchase electric energy from its incumbent electric utility.
b. Except as provided in subdivision 4, the demands of individual retail customers may not be aggregated or combined for the purpose of meeting the demand limitations of this provision, any other provision of this chapter to the contrary notwithstanding. For the purposes of this section, each noncontiguous site will nevertheless constitute an individual retail customer even though one or more such sites may be under common ownership of a single person.
c. If such customer does purchase electric energy from licensed suppliers after the expiration or termination of capped rates, it shall not thereafter be entitled to purchase electric energy from the incumbent electric utility without giving five years' advance written notice of such intention to such utility, except where such customer demonstrates to the Commission, after notice and opportunity for hearing, through clear and convincing evidence that its supplier has failed to perform, or has anticipatorily breached its duty to perform, or otherwise is about to fail to perform, through no fault of the customer, and that such customer is unable to obtain service at reasonable rates from an alternative supplier. If, as a result of such proceeding, the Commission finds it in the public interest to grant an exemption from the five-year notice requirement, such customer may thereafter purchase electric energy at the costs of such utility, as determined by the Commission pursuant to subdivision 3 d hereof, for the remainder of the five-year notice period, after which point the customer may purchase electric energy from the utility under rates, terms and conditions determined pursuant to § 56-585.1. However, such customer shall be allowed to individually purchase electric energy from the utility under rates, terms, and conditions determined pursuant to § 56-585.1 if, upon application by such customer, the Commission finds that neither such customer's incumbent electric utility nor retail customers of such utility that do not choose to obtain electric energy from alternate suppliers will be adversely affected in a manner contrary to the public interest by granting such petition. In making such determination, the Commission shall take into consideration, without limitation, the impact and effect of any and all other previously approved petitions of like type with respect to such incumbent electric utility. Any customer that returns to purchase electric energy from its incumbent electric utility, before or after expiration of the five-year notice period, shall be subject to minimum stay periods equal to those prescribed by the Commission pursuant to subdivision C 1.
d. The costs of serving a customer that has received an exemption from the five-year notice requirement under subdivision 3 c hereof shall be the market-based costs of the utility, including (i) the actual expenses of procuring such electric energy from the market, (ii) additional administrative and transaction costs associated with procuring such energy, including, but not limited to, costs of transmission, transmission line losses, and ancillary services, and (iii) a reasonable margin as determined pursuant to the provisions of subdivision A 2 of § 56-585.1. The methodology established by the Commission for determining such costs shall ensure that neither utilities nor other retail customers are adversely affected in a manner contrary to the public interest.
4. Two or more individual nonresidential retail customers of electric energy within the Commonwealth, whose individual demand during the most recent calendar year did not exceed five megawatts, may petition the Commission for permission to aggregate or combine their demands, for the purpose of meeting the demand limitations of subdivision 3, so as to become qualified to purchase electric energy from any supplier of electric energy licensed to sell retail electric energy within the Commonwealth under the conditions specified in subdivision 3. The Commission may, after notice and opportunity for hearing, approve such petition if it finds that:
a. Neither such customers' incumbent electric utility nor retail customers of such utility that do not choose to obtain electric energy from alternate suppliers will be adversely affected in a manner contrary to the public interest by granting such petition. In making such determination, the Commission shall take into consideration, without limitation, the impact and effect of any and all other previously approved petitions of like type with respect to such incumbent electric utility; and
b. Approval of such petition is consistent with the public interest.
If such petition is approved, all customers whose load has been aggregated or combined shall thereafter be subject in all respects to the provisions of subdivision 3 and shall be treated as a single, individual customer for the purposes of said subdivision. In addition, the Commission shall impose reasonable periodic monitoring and reporting obligations on such customers to demonstrate that they continue, as a group, to meet the demand limitations of subdivision 3. If the Commission finds, after notice and opportunity for hearing, that such group of customers no longer meets the above demand limitations, the Commission may revoke its previous approval of the petition, or take such other actions as may be consistent with the public interest.
5. Individual retail customers of electric energy within the Commonwealth, regardless of customer class, shall be permitted:
a. To purchase electric energy provided 100 percent from renewable energy from any supplier of electric energy licensed to sell retail electric energy within the Commonwealth, other than any incumbent electric utility that is not the incumbent electric utility serving the exclusive service territory in which such a customer is located, if the incumbent electric utility serving the exclusive service territory does not offer an approved tariff for electric energy provided 100 percent from renewable energy; and
b. To continue purchasing renewable energy pursuant to the terms of a power purchase agreement in effect on the date there is filed with the Commission a tariff for the incumbent electric utility that serves the exclusive service territory in which the customer is located to offer electric energy provided 100 percent from renewable energy, for the duration of such agreement.
6. To the extent that an incumbent electric utility has elected as of February 1, 2019, the Fixed Resource Requirement alternative as a Load Serving Entity in the PJM Region and continues to make such election and is therefore required to obtain capacity for all load and expected load growth in its service area, any customer of a utility subject to that requirement that purchases energy pursuant to subdivision 3 or 4 from a supplier licensed to sell retail electric energy within the Commonwealth shall continue to pay its incumbent electric utility for the non-fuel generation capacity and transmission related costs incurred by the incumbent electric utility in order to meet the customer's capacity obligations, pursuant to the incumbent electric utility's standard tariff that has been approved by and is on file with the Commission. In the case of such customer, the advance written notice period established in subdivisions 3 c and d shall be three years. This subdivision shall not apply to the customers of licensed suppliers that (i) had an agreement with a licensed supplier entered into before February 1, 2019, or (ii) had aggregation petitions pending before the Commission prior to January 1, 2019, unless and until any customer referenced in clause (i) or (ii) has returned to purchase electric energy from its incumbent electric utility, pursuant to the provisions of subdivision 3 or 4, and is receiving electric energy from such incumbent electric utility.
7. A tariff for one or more classes of residential customers filed with the Commission for approval by a cooperative on or after July 1, 2010, shall be deemed to offer a tariff for electric energy provided 100 percent from renewable energy if it provides undifferentiated electric energy and the cooperative retires a quantity of renewable energy certificates equal to 100 percent of the electric energy provided pursuant to such tariff. A tariff for one or more classes of nonresidential customers filed with the Commission for approval by a cooperative on or after July 1, 2012, shall be deemed to offer a tariff for electric energy provided 100 percent from renewable energy if it provides undifferentiated electric energy and the cooperative retires a quantity of renewable energy certificates equal to 100 percent of the electric energy provided pursuant to such tariff. For purposes of this section, "renewable energy certificate" means, with respect to cooperatives, a tradable commodity or instrument issued by a regional transmission entity or affiliate or successor thereof in the United States that validates the generation of electricity from renewable energy sources or that is certified under a generally recognized renewable energy certificate standard. One renewable energy certificate equals 1,000 kWh or one MWh of electricity generated from renewable energy. A cooperative offering electric energy provided 100 percent from renewable energy pursuant to this subdivision that involves the retirement of renewable energy certificates shall disclose to its retail customers who express an interest in purchasing energy pursuant to such tariff (i) that the renewable energy is comprised of the retirement of renewable energy certificates, (ii) the identity of the entity providing the renewable energy certificates, and (iii) the sources of renewable energy being offered.
B. The Commission shall promulgate such rules and regulations as may be necessary to implement the provisions of this section.
C. 1. By January 1, 2002, the Commission shall promulgate regulations establishing whether and, if so, for what minimum periods, customers who request service from an incumbent electric utility pursuant to subsection D of § 56-582 or a default service provider, after a period of receiving service from other suppliers of electric energy, shall be required to use such service from such incumbent electric utility or default service provider, as determined to be in the public interest by the Commission.
2. Subject to (i) the availability of capped rate service under § 56-582, and (ii) the transfer of the management and control of an incumbent electric utility's transmission assets to a regional transmission entity after approval of such transfer by the Commission under § 56-579, retail customers of such utility (a) purchasing such energy from licensed suppliers and (b) otherwise subject to minimum stay periods prescribed by the Commission pursuant to subdivision 1, shall nevertheless be exempt from any such minimum stay obligations by agreeing to purchase electric energy at the market-based costs of such utility or default providers after a period of obtaining electric energy from another supplier. Such costs shall include (i) the actual expenses of procuring such electric energy from the market, (ii) additional administrative and transaction costs associated with procuring such energy, including, but not limited to, costs of transmission, transmission line losses, and ancillary services, and (iii) a reasonable margin. The methodology of ascertaining such costs shall be determined and approved by the Commission after notice and opportunity for hearing and after review of any plan filed by such utility to procure electric energy to serve such customers. The methodology established by the Commission for determining such costs shall be consistent with the goals of (a) promoting the development of effective competition and economic development within the Commonwealth as provided in subsection A of § 56-596, and (b) ensuring that neither incumbent utilities nor retail customers that do not choose to obtain electric energy from alternate suppliers are adversely affected.
3. Notwithstanding the provisions of subsection D of § 56-582 and subsection C of § 56-585, however, any such customers exempted from any applicable minimum stay periods as provided in subdivision 2 shall not be entitled to purchase retail electric energy thereafter from their incumbent electric utilities, or from any distributor required to provide default service under subsection B of § 56-585, at the capped rates established under § 56-582, unless such customers agree to satisfy any minimum stay period then applicable while obtaining retail electric energy at capped rates.
4. The Commission shall promulgate such rules and regulations as may be necessary to implement the provisions of this subsection, which rules and regulations shall include provisions specifying the commencement date of such minimum stay exemption program.
1999, c. 411; 2001, c. 748; 2003, cc. 795, 990; 2004, c. 827; 2007, cc. 888, 933; 2010, cc. 326, 397; 2019, c. 833.
A. The Commission shall conduct a pilot program under which two or more nonresidential customers that, as of February 25, 2019, had filed applications seeking to aggregate their load pursuant to subdivision A 4 of § 56-577 within the service territory of a Phase II Utility, as that term is defined in subsection A of § 56-585.1, shall be permitted to purchase electric energy from any supplier of electric energy licensed to sell electric energy within the Commonwealth, subject to the following terms, conditions, and restrictions:
1. A pilot program shall be conducted within the certified service territory of the Phase II Utility in which such nonresidential customers are located.
2. The aggregated load participating in the pilot program shall not exceed 200 megawatts.
3. All customers participating in the pilot program shall be subject in all respects to the provisions of subdivision A 3 of § 56-577, with participation in this pilot program being deemed to satisfy subdivision A 4 of § 56-577 and with the load set forth in each application being treated as a single, individual customer for purposes of said subdivision, and shall submit an annual report to the Commission by March 31 each year to demonstrate that, for the preceding calendar year, such load continued to meet the demand limitations of subdivision A 3 of § 56-577.
B. The Commission shall review the pilot program established pursuant to subsection A in 2022.
2020, c. 796.
A. All distributors shall have the obligation to connect any retail customer, including those using distributed generation, located within its service territory to those facilities of the distributor that are used for delivery of retail electric energy, subject to Commission rules and regulations and approved tariff provisions relating to connection of service.
B. Except as otherwise provided in this chapter, every distributor shall provide distribution service within its service territory on a basis which is just, reasonable, and not unduly discriminatory to suppliers of electric energy, including distributed generation, as the Commission may determine. The distribution services provided to each supplier of electric energy shall be comparable in quality to those provided by the distribution utility to itself or to any affiliate.
C. The Commission shall establish interconnection standards to ensure transmission and distribution safety and reliability, which standards shall not be inconsistent with nationally recognized standards acceptable to the Commission. In adopting standards pursuant to this subsection, the Commission shall seek to prevent barriers to new technology and shall not make compliance unduly burdensome and expensive. The Commission shall determine questions about the ability of specific equipment to meet interconnection standards.
D. The Commission shall consider developing expedited permitting processes for small generation facilities of fifty megawatts or less. The Commission shall also consider developing a standardized permitting process and interconnection arrangements for those power systems less than 500 kilowatts which have demonstrated approval from a nationally recognized testing laboratory acceptable to the Commission.
E. Upon the separation and deregulation of the generation function and services of incumbent electric utilities, the Commission shall retain jurisdiction over utilities' electric transmission function and services, to the extent not preempted by federal law. Nothing in this section shall impair the Commission's authority under §§ 56-46.1, 56-46.2, and 56-265.2 with respect to the construction of electric transmission facilities.
A. As set forth in § 56-577, each incumbent electric utility owning, operating, controlling, or having an entitlement to transmission capacity shall join or establish a regional transmission entity, which hereafter may be referred to as "RTE," to which such utility shall transfer the management and control of its transmission assets, subject to the following:
1. No such incumbent electric utility shall transfer to any person any ownership or control of, or any responsibility to operate, any portion of any transmission system located in the Commonwealth prior to July 1, 2004, and without obtaining, following notice and hearing, the prior approval of the Commission, as hereinafter provided. However, each incumbent electric utility shall file an application for approval pursuant to this section by July 1, 2003, and shall transfer management and control of its transmission assets to a regional transmission entity by January 1, 2005, subject to Commission approval as provided in this section.
2. The Commission shall develop rules and regulations under which any such incumbent electric utility owning, operating, controlling, or having an entitlement to transmission capacity within the Commonwealth, may transfer all or part of such control, ownership or responsibility to an RTE, upon such terms and conditions that the Commission determines will:
a. Promote:
(1) Practices for the reliable planning, operating, maintaining, and upgrading of the transmission systems and any necessary additions thereto; and
(2) Policies for the pricing and access for service over such systems that are safe, reliable, efficient, not unduly discriminatory and consistent with the orderly development of competition in the Commonwealth;
b. Be consistent with lawful requirements of the Federal Energy Regulatory Commission;
c. Be effectuated on terms that fairly compensate the transferor;
d. Generally promote the public interest, and are consistent with (i) ensuring that consumers' needs for economic and reliable transmission are met and (ii) meeting the transmission needs of electric generation suppliers both within and without this Commonwealth, including those that do not own, operate, control or have an entitlement to transmission capacity.
B. The Commission shall also adopt rules and regulations, with appropriate public input, establishing elements of regional transmission entity structures essential to the public interest, which elements shall be applied by the Commission in determining whether to authorize transfer of ownership or control from an incumbent electric utility to a regional transmission entity.
C. The Commission shall, to the fullest extent permitted under federal law, participate in any and all proceedings concerning regional transmission entities furnishing transmission services within the Commonwealth, before the Federal Energy Regulatory Commission. Such participation may include such intervention as is permitted state utility regulators under Federal Energy Regulatory Commission rules and procedures.
D. Nothing in this section shall be deemed to abrogate or modify:
1. The Commission's authority over transmission line or facility construction, enlargement or acquisition within this Commonwealth, as set forth in Chapter 10.1 (§ 56-265.1 et seq.) of this title;
2. The laws of this Commonwealth concerning the exercise of the right of eminent domain by a public service corporation pursuant to the provisions of Article 5 (§ 56-257 et seq.) of Chapter 10 of this title; or
3. The Commission's authority over retail electric energy sold to retail customers within the Commonwealth by licensed suppliers of electric service, including necessary reserve requirements, all as specified in § 56-587.
E. For purposes of this section, transmission capacity shall not include capacity that is primarily operated in a distribution function, as determined by the Commission, taking into consideration any binding federal precedents.
F. Any request to the Commission for approval of such transfer of ownership or control of or responsibility for transmission facilities shall include a study of the comparative costs and benefits thereof, which study shall analyze the economic effects of the transfer on consumers, including the effects of transmission congestion costs. The Commission may approve such a transfer if it finds, after notice and hearing, that the transfer satisfies the conditions contained in this section.
G. The Commission shall report annually to the Commission on Electric Utility Regulation its assessment of the practices and policies of the RTE. Such report shall set forth actions taken by the Commission regarding requests for the approval of any transfer of ownership or control of transmission facilities to an RTE, including a description of the economic effects of such proposed transfers on consumers.
1999, c. 411; 2001, c. 576; 2003, cc. 885, 990; 2007, cc. 888, 933; 2008, c. 883.
A. Subject to the provisions of § 56-585.1, the Commission shall continue to regulate pursuant to this title the distribution of retail electric energy to retail customers in the Commonwealth and, to the extent not prohibited by federal law, the transmission of electric energy in the Commonwealth.
B. The Commission shall continue to regulate, to the extent not prohibited by federal law, the reliability, quality and maintenance by transmitters and distributors of their transmission and retail distribution systems.
C. The Commission shall develop codes of conduct governing the conduct of incumbent electric utilities and affiliates thereof when any such affiliates provide, or control any entity that provides, generation, distribution, or transmission services, to the extent necessary to prevent impairment of competition. Nothing in this chapter shall prevent an incumbent electric utility from offering metering options to its customers.
D. The Commission shall permit the construction and operation of electrical generating facilities in Virginia upon a finding that such generating facility and associated facilities (i) will have no material adverse effect upon reliability of electric service provided by any regulated public utility, (ii) are required by the public convenience and necessity, if a petition for such permit is filed after July 1, 2007, and if they are to be constructed and operated by any regulated utility whose rates are regulated pursuant to § 56-585.1, and (iii) are not otherwise contrary to the public interest. In review of a petition for a certificate to construct and operate a generating facility described in this subsection, the Commission shall give consideration to the effect of the facility and associated facilities on the environment and establish such conditions as may be desirable or necessary to minimize adverse environmental impact as provided in § 56-46.1, unless exempt as a small renewable energy project for which the Department of Environmental Quality has issued a permit by rule pursuant to Article 5 (§ 10.1-1197.5 et seq.) of Chapter 11.1 of Title 10.1. In order to avoid duplication of governmental activities, any valid permit or approval required for an electric generating plant and associated facilities issued or granted by a federal, state or local governmental entity charged by law with responsibility for issuing permits or approvals regulating environmental impact and mitigation of adverse environmental impact or for other specific public interest issues such as building codes, transportation plans, and public safety, whether such permit or approval is prior to or after the Commission's decision, shall be deemed to satisfy the requirements of this section with respect to all matters that (i) are governed by the permit or approval or (ii) are within the authority of, and were considered by, the governmental entity in issuing such permit or approval, and the Commission shall impose no additional conditions with respect to such matters. Nothing in this section shall affect the ability of the Commission to keep the record of a case open. Nothing in this section shall affect any right to appeal such permits or approvals in accordance with applicable law. In the case of a proposed facility located in a region that was designated as of July 1, 2001, as serious nonattainment for the one-hour ozone standard as set forth in the federal Clean Air Act, the Commission shall not issue a decision approving such proposed facility that is conditioned upon issuance of any environmental permit or approval. The Commission shall complete any proceeding under this section, or under any provision of the Utility Facilities Act (§ 56-265.1 et seq.), involving an application for a certificate, permit, or approval required for the construction or operation by a public utility of a small renewable energy project as defined in § 10.1-1197.5, within nine months following the utility's submission of a complete application therefore. Small renewable energy projects as defined in § 10.1-1197.5 are in the public interest and in determining whether to approve such project, the Commission shall liberally construe the provisions of this title.
E. Nothing in this section shall impair the distribution service territorial rights of incumbent electric utilities, and incumbent electric utilities shall continue to provide distribution services within their exclusive service territories as established by the Commission. Subject to the provisions of § 56-585.1, the Commission shall continue to exercise its existing authority over the provision of electric distribution services to retail customers in the Commonwealth including, but not limited to, the authority contained in Chapters 10 (§ 56-232 et seq.) and 10.1 (§ 56-265.1 et seq.) of this title.
F. Nothing in this chapter shall impair the exclusive territorial rights of an electric utility owned or operated by a municipality as of July 1, 1999, or by an authority created by a governmental unit exempt from the referendum requirement of § 15.2-5403. Nor shall any provision of this chapter apply to any such electric utility unless (i) that municipality or that authority created by a governmental unit exempt from the referendum requirement of § 15.2-5403 elects to have this chapter apply to that utility or (ii) that utility, directly or indirectly, sells, offers to sell or seeks to sell electric energy to any retail customer eligible to purchase electric energy from any supplier in accordance with § 56-577 if that retail customer is outside the geographic area that was served by such municipality as of July 1, 1999, except (a) any area within the municipality that was served by an incumbent public utility as of that date but was thereafter served by an electric utility owned or operated by a municipality or by an authority created by a governmental unit exempt from the referendum requirement of § 15.2-5403 pursuant to the terms of a franchise agreement between the municipality and the incumbent public utility, or (b) where the geographic area served by an electric utility owned or operated by a municipality is changed pursuant to mutual agreement between the municipality and the affected incumbent public utility in accordance with § 56-265.4:1. If an electric utility owned or operated by a municipality as of July 1, 1999, or by an authority created by a governmental unit exempt from the referendum requirement of § 15.2-5403 is made subject to the provisions of this chapter pursuant to clause (i) or (ii) of this subsection, then in such event the provisions of this chapter applicable to incumbent electric utilities shall also apply to any such utility, mutatis mutandis.
G. The applicability of all provisions of this chapter except § 56-594 to any investor-owned incumbent electric utility supplying electric service to retail customers on January 1, 2003, whose service territory assigned to it by the Commission is located entirely within Dickenson, Lee, Russell, Scott, and Wise Counties shall be suspended effective July 1, 2003, so long as such utility does not provide retail electric services in any other service territory in any jurisdiction to customers who have the right to receive retail electric energy from another supplier. During any such suspension period, the utility's rates shall be (i) its capped rates established pursuant to § 56-582 for the duration of the capped rate period established thereunder, and (ii) determined thereafter by the Commission on the basis of such utility's prudently incurred costs pursuant to Chapter 10 (§ 56-232 et seq.) of this title.
H. The expiration date of any certificates granted by the Commission pursuant to subsection D, for which applications were filed with the Commission prior to July 1, 2002, shall be extended for an additional two years from the expiration date that otherwise would apply.
1999, c. 411; 2000, c. 991; 2001, cc. 738, 748, 755; 2002, c. 483; 2003, c. 719; 2004, cc. 262, 827; 2006, cc. 811, 819, 929, 941; 2007, cc. 877, 888, 933; 2009, cc. 808, 854.
A. The Commission shall regulate the rates of investor-owned incumbent electric utilities for the transmission of electric energy, to the extent not prohibited by federal law, and for the generation of electric energy and the distribution of electric energy to retail customers pursuant to this section and § 56-585.1.
B. In any proceeding to review base rates for a Phase I Utility that commences after July 1, 2023, if the Commission determines in its sole discretion that the utility's existing base rates will, on a going-forward basis, either produce (i) revenues in excess of the utility's authorized rate of return or (ii) revenues below the utility's authorized rate of return, then, notwithstanding any provision of law governing rate proceedings, the Commission shall order any reductions or increases, as applicable and necessary, to such base rates that it deems appropriate to ensure the resulting base rates (a) are just and reasonable and (b) provide the utility an opportunity to recover its costs of providing services over the rate period ending on December 31 of the year of the utility's succeeding review and earn a fair rate of return authorized pursuant to the provisions governing such review proceeding. Such determination shall be limited to the Phase I Utility's base rates and shall not consider the costs or revenues recovered in any rate adjustment clause authorized pursuant to this chapter.
C. In any proceeding to review base rates for a Phase II Utility that commences after July 1, 2023, if the Commission determines in its sole discretion that the utility's existing base rates will, on a going-forward basis, either produce (i) revenues in excess of the utility's authorized rate of return or (ii) revenues below the utility's authorized rate of return, then, notwithstanding any provision of subdivision A 8 of § 56-585.1, the Commission shall order any reductions or increases, as applicable and necessary, to such base rates that it deems appropriate to ensure the resulting base rates (a) are just and reasonable and (b) provide the utility an opportunity to recover its costs of providing services over the rate period ending on December 31 of the year of the utility's succeeding review and earn a fair rate of return on its base rates as determined in subdivision A 2 of § 56-585.1. Such determination shall be limited to the Phase II Utility's base rates and shall not consider the costs or revenues recovered in any rate adjustment clause authorized pursuant to subdivision A 6 of § 56-585.1 that has not been combined with the utility's base rates. The Commission shall use the most recently ended 12-month test period, along with normalization of nonrecurring test period costs and annualized adjustments for future costs, as the basis for determining the appropriateness of any rate adjustment. In any such filing to review base rates, a Phase II Utility shall separately project future costs over each 12-month period ending on December 31 of the year of the utility's succeeding rate periods. The Commission may, to the extent it finds such action aligns with the utility's projected cost of service, direct that any reduction or increase to the utility's rates for generation and distribution services be implemented on a staggered basis at the commencement and midpoint of the succeeding review or rate period.
D. Beginning July 1, 1999, and thereafter, no cooperative that was a member of a power supply cooperative on January 1, 1999, shall be obligated to file any rate rider as a consequence of an increase or decrease in the rates, other than fuel costs, of its wholesale supplier, nor must any adjustment be made to such cooperative's rates as a consequence thereof.
E. Except for the provision of default services under § 56-585 or emergency services in § 56-586, nothing in this chapter shall authorize the Commission to regulate the rates or charges for electric service to the Commonwealth and its municipalities.
F. As used in this section:
"Base rates" means rates for generation and distribution services.
"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.
1999, c. 411; 2000, c. 991; 2007, cc. 888, 933; 2023, cc. 497, 498, 757, 775.
A. The Commission shall establish capped rates, effective January 1, 2001, for each service territory of every incumbent utility as follows:
1. Capped rates shall be established for customers purchasing bundled electric transmission, distribution and generation services from an incumbent electric utility.
2. Capped rates for electric generation services, only, shall also be established for the purpose of effecting customer choice for those retail customers authorized under this chapter to purchase generation services from a supplier other than the incumbent utility during this period.
3. The capped rates established under this section shall be the rates in effect for each incumbent utility as of the effective date of this chapter, or rates subsequently placed into effect pursuant to a rate application filed by an incumbent electric utility with the Commission prior to January 1, 2001, and subsequently approved by the Commission, and made by an incumbent electric utility that is not currently bound by a rate case settlement adopted by the Commission that extends in its application beyond January 1, 2002. If such rate application is filed, the rates proposed therein shall go into effect on January 1, 2001, but such rates shall be interim in nature and subject to refund until such time as the Commission has completed its investigation of such application. Any amount of the rates found excessive by the Commission shall be subject to refund with interest, as may be ordered by the Commission. The Commission shall act upon such applications prior to January 1, 2002. Such rate application and the Commission's approval shall give due consideration, on a forward-looking basis, to the justness and reasonableness of rates to be effective for a period of time ending as late as July 1, 2007. The capped rates established under this section, which include rates, tariffs, electric service contracts, and rate programs (including experimental rates, regardless of whether they otherwise would expire), shall be such rates, tariffs, contracts, and programs of each incumbent electric utility, provided that experimental rates and rate programs may be closed to new customers upon application to the Commission. Such capped rates shall also include rates for new services where, subsequent to January 1, 2001, rate applications for any such rates are filed by incumbent electric utilities with the Commission and are thereafter approved by the Commission. In establishing such rates for new services, the Commission may use any rate method that promotes the public interest and that is fairly compensatory to any utilities requesting such rates.
B. The Commission may adjust such capped rates in connection with the following: (i) utilities' recovery of fuel and purchased power costs pursuant to § 56-249.6, and, if applicable, in accordance with the terms of any Commission order approving the divestiture of generation assets pursuant to § 56-590, (ii) any changes in the taxation by the Commonwealth of incumbent electric utility revenues, (iii) any financial distress of the utility beyond its control, (iv) with respect to cooperatives that were not members of a power supply cooperative on January 1, 1999, and as long as they do not become members, their cost of purchased wholesale power and discounts from capped rates to match the cost of providing distribution services, (v) with respect to cooperatives that were members of a power supply cooperative on January 1, 1999, their recovery of fuel costs, through the wholesale power cost adjustment clauses of their tariffs pursuant to § 56-231.33, and (vi) with respect to incumbent electric utilities that were not, as of the effective date of this chapter, bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002, the Commission shall adjust such utilities' capped rates, not more than once in any 12-month period, for the timely recovery of their incremental costs for transmission or distribution system reliability and compliance with state or federal environmental laws or regulations to the extent such costs are prudently incurred on and after July 1, 2004. Any adjustments pursuant to § 56-249.6 and clause (i) of this subsection by an incumbent electric utility that transferred all of its generation assets to an affiliate with the approval of the Commission pursuant to § 56-590 prior to January 1, 2002, shall be effective only on and after July 1, 2007. Notwithstanding the provisions of § 56-249.6, the Commission may authorize tariffs that include incentives designed to encourage an incumbent electric utility to reduce its fuel costs by permitting retention of a portion of cost savings resulting from fuel cost reductions or by other methods determined by the Commission to be fair and reasonable to the utility and its customers.
C. A utility may petition the Commission to terminate the capped rates to all customers any time after January 1, 2004, and such capped rates may be terminated upon the Commission finding of an effectively competitive market for generation services within the service territory of that utility. If its capped rates, as established and adjusted from time to time pursuant to subsections A and B, are continued after January 1, 2004, an incumbent electric utility that is not, as of the effective date of this chapter, bound by a rate case settlement adopted by the Commission that extends in its application beyond January 1, 2002, may petition the Commission, during the period January 1, 2004, through June 30, 2007, for approval of a one-time change in its rates, and if the capped rates are continued after July 1, 2007, such incumbent electric utility may at any time after July 1, 2007, petition the Commission for approval of a one-time change in its rates. Any change in rates pursuant to this subsection by an incumbent electric utility that divested its generation assets with approval of the Commission pursuant to § 56-590 prior to January 1, 2002, shall be in accordance with the terms of any Commission order approving such divestiture. Any petition for changes to capped rates filed pursuant to this subsection shall be governed by the provisions of Chapter 10 (§ 56-232 et seq.) of this title.
D. Until the expiration or termination of capped rates as provided in this section, the incumbent electric utility, consistent with the functional separation plan implemented under § 56-590, shall make electric service available at capped rates established under this section to any customer in the incumbent electric utility's service territory, including any customer that, until the expiration or termination of capped rates, requests such service after a period of utilizing service from another supplier.
E. During the period when capped rates are in effect for an incumbent electric utility, such utility may file with the Commission a plan describing the method used by such utility to assure full funding of its nuclear decommissioning obligation and specifying the amount of the revenues collected under either the capped rates, as provided in this section, or the wires charges, as provided in former § 56-583, that are dedicated to funding such nuclear decommissioning obligation under the plan. The Commission shall approve the plan upon a finding that the plan is not contrary to the public interest.
F. The capped rates established pursuant to this section shall expire on December 31, 2008, unless sooner terminated by the Commission pursuant to the provisions of subsection C; however, rates after the expiration or termination of capped rates shall equal capped rates until such rates are changed pursuant to other provisions of this title.
1999, c. 411; 2000, cc. 942, 991; 2001, c. 748; 2004, c. 827; 2007, cc. 888, 933; 2008, c. 883.
Just and reasonable net stranded costs, to the extent that they exceed zero value in total for the incumbent electric utility, shall be recoverable by each incumbent electric utility provided each incumbent electric utility shall only recover its just and reasonable net stranded costs through either capped rates as provided in § 56-582. To the extent not preempted by federal law, the establishment by the Commission of wires charges for any distribution cooperative shall be conditioned upon such cooperative entering into binding commitments by which it will pay to any power supply cooperative of which such distribution cooperative is or was a member, as compensation for such power supply cooperative's stranded costs, all or part of the proceeds of such wires charges, as determined by the Commission.
A. The Commission shall, after notice and opportunity for hearing, (i) determine the components of default service and (ii) establish one or more programs making such services available to retail customers requiring them during the availability throughout the Commonwealth of customer choice for all retail customers as established pursuant to § 56-577. For purposes of this chapter, "default service" means service made available under this section to retail customers who (i) do not affirmatively select a supplier, (ii) are unable to obtain service from an alternative supplier, or (iii) have contracted with an alternative supplier who fails to perform. Availability of default service shall expire upon the expiration or termination of capped rates.
B. A distributor shall have the obligation and right to be the supplier of default services in its certificated service territory, and shall do so, in a safe and reliable manner, at rates determined pursuant to subsection C; however, the Commission may not require a distributor, or affiliate thereof, to provide any such services outside the territory in which such distributor provides service.
C. Until the expiration or termination of capped rates, the rates for default service shall equal the capped rates established pursuant to subdivision A 2 of § 56-582.
D. A distribution electric cooperative, or one or more affiliates thereof, shall have the obligation and right to be the supplier of default services in its certificated service territory. A distribution electric cooperative's rates for such default services shall be the capped rate for the duration of the capped rate period. Subsections B and C shall not apply to a distribution electric cooperative or its rates. Such default services, for the purposes of this subsection, shall include the supply of electric energy.
1999, c. 411; 2000, c. 991; 2001, c. 748; 2003, c. 885; 2004, c. 827; 2007, cc. 888, 933.
A. During the first six months of 2009, the Commission shall, after notice and opportunity for hearing, initiate proceedings to review the rates, terms and conditions for the provision of generation, distribution and transmission services of each investor-owned incumbent electric utility. Such proceedings shall be governed by the provisions of Chapter 10 (§ 56-232 et seq.), except as modified herein. In such proceedings the Commission shall determine fair rates of return on common equity applicable to the generation and distribution services of the utility. In so doing, the Commission may use any methodology to determine such return it finds consistent with the public interest, but such return shall not be set lower than the average of the returns on common equity reported to the Securities and Exchange Commission for the three most recent annual periods for which such data are available by not less than a majority, selected by the Commission as specified in subdivision 2 b, of other investor-owned electric utilities in the peer group of the utility, nor shall the Commission set such return more than 300 basis points higher than such average. The peer group of the utility shall be determined in the manner prescribed in subdivision 2 b. The Commission may increase or decrease such combined rate of return by up to 100 basis points based on the generating plant performance, customer service, and operating efficiency of a utility, as compared to nationally recognized standards determined by the Commission to be appropriate for such purposes. In such a proceeding, the Commission shall determine the rates that the utility may charge until such rates are adjusted. If the Commission finds that the utility's combined rate of return on common equity is more than 50 basis points below the combined rate of return as so determined, it shall be authorized to order increases to the utility's rates necessary to provide the opportunity to fully recover the costs of providing the utility's services and to earn not less than such combined rate of return. If the Commission finds that the utility's combined rate of return on common equity is more than 50 basis points above the combined rate of return as so determined, it shall be authorized either (i) to order reductions to the utility's rates it finds appropriate, provided that the Commission may not order such rate reduction unless it finds that the resulting rates will provide the utility with the opportunity to fully recover its costs of providing its services and to earn not less than the fair rates of return on common equity applicable to the generation and distribution services; or (ii) to direct that 60 percent of the amount of the utility's earnings that were more than 50 basis points above the fair combined rate of return for calendar year 2008 be credited to customers' bills, in which event such credits shall be amortized over a period of six to 12 months, as determined at the discretion of the Commission, following the effective date of the Commission's order and be allocated among customer classes such that the relationship between the specific customer class rates of return to the overall target rate of return will have the same relationship as the last approved allocation of revenues used to design base rates. Commencing in 2011, the Commission, after notice and opportunity for hearing, shall conduct reviews of the rates, terms and conditions for the provision of generation, distribution and transmission services by each investor-owned incumbent electric utility, subject to the following provisions:
1. Rates, terms and conditions for each service shall be reviewed separately on an unbundled basis, and such reviews shall be conducted in a single, combined proceeding. Pursuant to subsection A of § 56-585.1:1, the Commission shall conduct a review for a Phase I Utility in 2020, utilizing the three successive 12-month test periods beginning January 1, 2017, and ending December 31, 2019. Thereafter, reviews for a Phase I Utility will be on a triennial basis with subsequent proceedings utilizing the three successive 12-month test periods ending December 31 immediately preceding the year in which such review proceeding is conducted. Pursuant to subsection A of § 56-585.1:1, the Commission shall conduct a review for a Phase II Utility in 2021, utilizing the four successive 12-month test periods beginning January 1, 2017, and ending December 31, 2020, with subsequent reviews on a biennial basis commencing in 2023, with such proceedings utilizing the two successive 12-month test periods ending December 31 immediately preceding the year in which such review proceeding is conducted. For purposes of this section, a Phase I Utility is an investor-owned incumbent electric utility that was, as of July 1, 1999, not bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002, and a Phase II Utility is an investor-owned incumbent electric utility that was bound by such a settlement.
2. Subject to the provisions of subdivision 6, the fair rate of return on common equity applicable separately to the generation and distribution services of such utility, and for the two such services combined, and for any rate adjustment clauses approved under subdivision 5 or 6, shall be determined by the Commission during each such review, as follows:
a. The Commission may use any methodology to determine such return it finds consistent with the public interest. However, for a Phase I Utility, for applications received by the Commission on or after January 1, 2020, such return shall not be set lower than the average of either (i) the returns on common equity reported to the Securities and Exchange Commission for the three most recent annual periods for which such data are available by not less than a majority, selected by the Commission as specified in subdivision 2 b, of other investor-owned electric utilities in the peer group of the utility subject to such triennial review or (ii) the authorized returns on common equity that are set by the applicable regulatory commissions for the same selected peer group, nor shall the Commission set such return more than 150 basis points higher than such average.
b. For a Phase I Utility, in selecting such majority of peer group investor-owned electric utilities for applications received by the Commission on or after January 1, 2020, the Commission shall first remove from such group the two utilities within such group that have the lowest reported or authorized, as applicable, returns of the group, as well as the two utilities within such group that have the highest reported or authorized, as applicable, returns of the group, and the Commission shall then select a majority of the utilities remaining in such peer group. In its final order regarding such triennial review, the Commission shall identify the utilities in such peer group it selected for the calculation of such limitation. With respect to a Phase I Utility, for purposes of this subdivision 2, an investor-owned electric utility shall be deemed part of such peer group if (i) its principal operations are conducted in the southeastern United States east of the Mississippi River in either the states of West Virginia or Kentucky or in those states south of Virginia, excluding the state of Tennessee, (ii) it is a vertically-integrated electric utility providing generation, transmission, and distribution services whose facilities and operations are subject to state public utility regulation in the state where its principal operations are conducted, (iii) it had a long-term bond rating assigned by Moody's Investors Service of at least Baa at the end of the most recent test period subject to such review, and (iv) it is not an affiliate of the utility subject to such review or a utility whose fair rate of return on common equity is determined by the Commission.
c. The Commission may increase or decrease the utility's combined rate of return for generation and distribution services by up to 50 basis points based on factors that may include reliability, generating plant performance, customer service, and operating efficiency of a utility. Any such adjustment to the combined rate of return for generation and distribution services shall include consideration of nationally recognized standards determined by the Commission to be appropriate for such purposes.
d. In any Current Proceeding, the Commission shall determine whether the Current Return has increased, on a percentage basis, above the Initial Return by more than the increase, expressed as a percentage, in the United States Average Consumer Price Index for all items, all urban consumers (CPI-U), as published by the Bureau of Labor Statistics of the United States Department of Labor, since the date on which the Commission determined the Initial Return. If so, the Commission may conduct an additional analysis of whether it is in the public interest to utilize such Current Return for the Current Proceeding then pending. A finding of whether the Current Return justifies such additional analysis shall be made without regard to any enhanced rate of return on common equity awarded pursuant to the provisions of subdivision 6. Such additional analysis shall include, but not be limited to, a consideration of overall economic conditions, the level of interest rates and cost of capital with respect to business and industry, in general, as well as electric utilities, the current level of inflation and the utility's cost of goods and services, the effect on the utility's ability to provide adequate service and to attract capital if less than the Current Return were utilized for the Current Proceeding then pending, and such other factors as the Commission may deem relevant. If, as a result of such analysis, the Commission finds that use of the Current Return for the Current Proceeding then pending would not be in the public interest, then the lower limit imposed by subdivision 2 a on the return to be determined by the Commission for such utility shall be calculated, for that Current Proceeding only, by increasing the Initial Return by a percentage at least equal to the increase, expressed as a percentage, in the United States Average Consumer Price Index for all items, all urban consumers (CPI-U), as published by the Bureau of Labor Statistics of the United States Department of Labor, since the date on which the Commission determined the Initial Return. For purposes of this subdivision:
"Current Proceeding" means any proceeding conducted under any provisions of this subsection that require or authorize the Commission to determine a fair combined rate of return on common equity for a utility and that will be concluded after the date on which the Commission determined the Initial Return for such utility.
"Current Return" means the minimum fair combined rate of return on common equity required for any Current Proceeding by the limitation regarding a utility's peer group specified in subdivision 2 a.
"Initial Return" means the fair combined rate of return on common equity determined for such utility by the Commission on the first occasion after July 1, 2009, under any provision of this subsection pursuant to the provisions of subdivision 2 a.
e. In addition to other considerations, in setting the return on equity within the range allowed by this section, the Commission shall strive to maintain costs of retail electric energy that are cost competitive with costs of retail electric energy provided by the other peer group investor-owned electric utilities.
f. The determination of such returns shall be made by the Commission on a stand-alone basis, and specifically without regard to any return on common equity or other matters determined with regard to facilities described in subdivision 6.
g. If the combined rate of return on common equity earned by the generation and distribution services is no more than 50 basis points above or below the return as so determined or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, such return is no more than 70 basis points above or below the return as so determined, such combined return shall not be considered either excessive or insufficient, respectively. However, for any test period commencing after December 31, 2012, for a Phase II Utility, and after December 31, 2013, for a Phase I Utility, if the utility has, during the test period or periods under review, earned below the return as so determined, whether or not such combined return is within 70 basis points of the return as so determined, the utility may petition the Commission for approval of an increase in rates in accordance with the provisions of subdivision 8 a as if it had earned more than 70 basis points below a fair combined rate of return, and such proceeding shall otherwise be conducted in accordance with the provisions of this section. The provisions of this subdivision are subject to the provisions of subdivision 8.
h. Any amount of a utility's earnings directed by the Commission to be credited to customers' bills pursuant to this section shall not be considered for the purpose of determining the utility's earnings in any subsequent review.
3. Each such utility shall make a triennial filing by March 31 of every third year, with such filings commencing for a Phase I Utility in 2020, and such filings commencing for a Phase II Utility in 2021 and terminating thereafter. Such filing shall encompass the three successive 12-month test periods ending December 31 immediately preceding the year in which such proceeding is conducted, except that the filing for a Phase II Utility in 2021 shall encompass the four successive 12-month test periods ending December 31, 2020. After 2021, each Phase II Utility shall make a biennial filing by March 31 of every second year, except that the 2023 filing for a Phase II Utility shall be made on or after July 1, 2023. All biennial filings shall encompass the two successive 12-month test periods ending December 31 immediately preceding the year in which such review proceeding is conducted. All such filings shall consist of the schedules contained in the Commission's rules governing utility rate increase applications, and in every such case the filing for each year shall be identified separately and shall be segregated from any other year encompassed by the filing. In a filing under this subdivision that does not result in an overall rate change, a utility may propose an adjustment to one or more tariffs that are revenue neutral to the utility.
If the Commission determines that rates should be revised or credits be applied to customers' bills pursuant to subdivision 8 or 10, any rate adjustment clauses previously implemented related to facilities utilizing simple-cycle combustion turbines described in subdivision 6, shall be combined with the utility's costs, revenues, and investments until the amounts that are the subject of such rate adjustment clauses are fully recovered. The Commission shall combine such clauses with the utility's costs, revenues, and investments only after it makes its initial determination with regard to necessary rate revisions or credits to customers' bills, and the amounts thereof, but after such clauses are combined as specified in this paragraph, they shall thereafter be considered part of the utility's costs, revenues, and investments for the purposes of future review proceedings.
As of July 1, 2023, a Phase II Utility shall select a subset of rate adjustment clauses previously implemented pursuant to subdivision 5 or 6 having a combined annual revenue requirement, as of July 1, 2023, of at least $350 million and combine such rate adjustment clauses with the utility's costs, revenues, and investments for generation and distribution services. After such rate adjustment clauses are combined as specified in this paragraph, such rate adjustment clauses shall be considered part of the utility's costs, revenues, and investments for the purposes of future biennial review proceedings, and the combination of such rate adjustment clauses shall be specifically subject to audit by the Commission in the utility's 2023 biennial review filing. Notwithstanding the provisions of subsection C of § 56-581, such combination shall not serve as the basis for an increase in a Phase II Utility's rates for generation and distribution services in its 2023 biennial proceeding.
4. The following costs incurred by the utility shall be deemed reasonable and prudent: (i) costs for transmission services provided to the utility by the regional transmission entity of which the utility is a member, as determined under applicable rates, terms and conditions approved by the Federal Energy Regulatory Commission; (ii) costs charged to the utility that are associated with demand response programs approved by the Federal Energy Regulatory Commission and administered by the regional transmission entity of which the utility is a member; and (iii) costs incurred by the utility to construct, operate, and maintain transmission lines and substations installed in order to provide service to a business park. Upon petition of a utility at any time after the expiration or termination of capped rates, but not more than once in any 12-month period, the Commission shall approve a rate adjustment clause under which such costs, including, without limitation, costs for transmission service; charges for new and existing transmission facilities, including costs incurred by the utility to construct, operate, and maintain transmission lines and substations installed in order to provide service to a business park; administrative charges; and ancillary service charges designed to recover transmission costs, shall be recovered on a timely and current basis from customers. Retail rates to recover these costs shall be designed using the appropriate billing determinants in the retail rate schedules.
5. A utility may at any time, after the expiration or termination of capped rates, but not more than once in any 12-month period, petition the Commission for approval of one or more rate adjustment clauses for the timely and current recovery from customers of the following costs:
a. Incremental costs described in clause (vi) of subsection B of § 56-582 incurred between July 1, 2004, and the expiration or termination of capped rates, if such utility is, as of July 1, 2007, deferring such costs consistent with an order of the Commission entered under clause (vi) of subsection B of § 56-582. The Commission shall approve such a petition allowing the recovery of such costs that comply with the requirements of clause (vi) of subsection B of § 56-582;
b. Projected and actual costs for the utility to design and operate fair and effective peak-shaving programs or pilot programs. The Commission shall approve such a petition if it finds that the program is in the public interest, provided that the Commission shall allow the recovery of such costs as it finds are reasonable;
c. Projected and actual costs for the utility to design, implement, and operate energy efficiency programs or pilot programs. Any such petition shall include a proposed budget for the design, implementation, and operation of the energy efficiency program, including anticipated savings from and spending on each program, and the Commission shall grant a final order on such petitions within eight months of initial filing. The Commission shall only approve such a petition if it finds that the program is in the public interest. If the Commission determines that an energy efficiency program or portfolio of programs is not in the public interest, its final order shall include all work product and analysis conducted by the Commission's staff in relation to that program that has bearing upon the Commission's determination. Such order shall adhere to existing protocols for extraordinarily sensitive information.
Energy efficiency pilot programs are in the public interest provided that the pilot program is (i) of limited scope, cost, and duration and (ii) intended to determine whether a new or substantially revised program would be cost-effective.
Prior to January 1, 2022, the Commission shall award a margin for recovery on operating expenses for energy efficiency programs and pilot programs, which margin shall be equal to the general rate of return on common equity determined as described in subdivision 2. Beginning January 1, 2022, and thereafter, if the Commission determines that the utility meets in any year the annual energy efficiency standards set forth in § 56-596.2, in the following year, the Commission shall award a margin on energy efficiency program operating expenses in that year, to be recovered through a rate adjustment clause, which margin shall be equal to the general rate of return on common equity determined as described in subdivision 2. If the Commission does not approve energy efficiency programs that, in the aggregate, can achieve the annual energy efficiency standards, the Commission shall award a margin on energy efficiency operating expenses in that year for any programs the Commission has approved, to be recovered through a rate adjustment clause under this subdivision, which margin shall equal the general rate of return on common equity determined as described in subdivision 2. Any margin awarded pursuant to this subdivision shall be applied as part of the utility's next rate adjustment clause true-up proceeding. The Commission shall also award an additional 20 basis points for each additional incremental 0.1 percent in annual savings in any year achieved by the utility's energy efficiency programs approved by the Commission pursuant to this subdivision, beyond the annual requirements set forth in § 56-596.2, provided that the total performance incentive awarded in any year shall not exceed 10 percent of that utility's total energy efficiency program spending in that same year.
The Commission shall annually monitor and report to the General Assembly the performance of all programs approved pursuant to this subdivision, including each utility's compliance with the total annual savings required by § 56-596.2, as well as the annual and lifecycle net and gross energy and capacity savings, related emissions reductions, and other quantifiable benefits of each program; total customer bill savings that the programs produce; utility spending on each program, including any associated administrative costs; and each utility's avoided costs and cost-effectiveness results.
Notwithstanding any other provision of law, unless the Commission finds in its discretion and after consideration of all in-state and regional transmission entity resources that there is a threat to the reliability or security of electric service to the utility's customers, the Commission shall not approve construction of any new utility-owned generating facilities that emit carbon dioxide as a by-product of combusting fuel to generate electricity unless the utility has already met the energy savings goals identified in § 56-596.2 and the Commission finds that supply-side resources are more cost-effective than demand-side or energy storage resources.
As used in this subdivision, "large general service customer" means a customer that has a verifiable history of having used more than one megawatt of demand from a single site.
Large general service customers shall be exempt from requirements that they participate in energy efficiency programs if the Commission finds that the large general service customer has, at the customer's own expense, implemented energy efficiency programs that have produced or will produce measured and verified results consistent with industry standards and other regulatory criteria stated in this section. The Commission shall, no later than June 30, 2021, adopt rules or regulations (a) establishing the process for large general service customers to apply for such an exemption, (b) establishing the administrative procedures by which eligible customers will notify the utility, and (c) defining the standard criteria that shall be satisfied by an applicant in order to notify the utility, including means of evaluation measurement and verification and confidentiality requirements. At a minimum, such rules and regulations shall require that each exempted large general service customer certify to the utility and Commission that its implemented energy efficiency programs have delivered measured and verified savings within the prior five years. In adopting such rules or regulations, the Commission shall also specify the timing as to when a utility shall accept and act on such notice, taking into consideration the utility's integrated resource planning process, as well as its administration of energy efficiency programs that are approved for cost recovery by the Commission. Savings from large general service customers shall be accounted for in utility reporting in the standards in § 56-596.2.
The notice of nonparticipation by a large general service customer shall be for the duration of the service life of the customer's energy efficiency measures. The Commission may on its own motion initiate steps necessary to verify such nonparticipant's achievement of energy efficiency if the Commission has a body of evidence that the nonparticipant has knowingly misrepresented its energy efficiency achievement.
A utility shall not charge such large general service customer for the costs of installing energy efficiency equipment beyond what is required to provide electric service and meter such service on the customer's premises if the customer provides, at the customer's expense, equivalent energy efficiency equipment. In all relevant proceedings pursuant to this section, the Commission shall take into consideration the goals of economic development, energy efficiency and environmental protection in the Commonwealth;
d. Projected and actual costs of compliance with renewable energy portfolio standard requirements pursuant to § 56-585.5 that are not recoverable under subdivision 6. The Commission shall approve such a petition allowing the recovery of such costs incurred as required by § 56-585.5, provided that the Commission does not otherwise find such costs were unreasonably or imprudently incurred;
e. Projected and actual costs of projects that the Commission finds to be necessary to mitigate impacts to marine life caused by construction of offshore wind generating facilities, as described in § 56-585.1:11, or to comply with state or federal environmental laws or regulations applicable to generation facilities used to serve the utility's native load obligations, including the costs of allowances purchased through a market-based trading program for carbon dioxide emissions. The Commission shall approve such a petition if it finds that such costs are necessary to comply with such environmental laws or regulations;
f. Projected and actual costs, not currently in rates, for the utility to design, implement, and operate programs approved by the Commission that accelerate the vegetation management of distribution rights-of-way. No costs shall be allocated to or recovered from customers that are served within the large general service rate classes for a Phase II Utility or that are served at subtransmission or transmission voltage, or take delivery at a substation served from subtransmission or transmission voltage, for a Phase I Utility; and
g. Projected and actual costs, not currently in rates, for the utility to design, implement, and operate programs approved by the Commission to provide incentives to (i) low-income, elderly, and disabled individuals or (ii) organizations providing residential services to low-income, elderly, and disabled individuals for the installation of, or access to, equipment to generate electric energy derived from sunlight, provided the low-income, elderly, and disabled individuals, or organizations providing residential services to low-income, elderly, and disabled individuals, first participate in incentive programs for the installation of measures that reduce heating or cooling costs.
Any rate adjustment clause approved under subdivision 5 c by the Commission shall remain in effect until the utility exhausts the approved budget for the energy efficiency program. The Commission shall have the authority to determine the duration or amortization period for any other rate adjustment clause approved under this subdivision.
6. To ensure the generation and delivery of a reliable and adequate supply of electricity, to meet the utility's projected native load obligations and to promote economic development, a utility may at any time, after the expiration or termination of capped rates, petition the Commission for approval of a rate adjustment clause for recovery on a timely and current basis from customers of the costs of (i) a coal-fueled generation facility that utilizes Virginia coal and is located in the coalfield region of the Commonwealth as described in § 15.2-6002, regardless of whether such facility is located within or without the utility's service territory, (ii) one or more other generation facilities, (iii) one or more major unit modifications of generation facilities, including the costs of any system or equipment upgrade, system or equipment replacement, or other cost reasonably appropriate to extend the combined operating license for or the operating life of one or more generation facilities utilizing nuclear power, (iv) one or more new underground facilities to replace one or more existing overhead distribution facilities of 69 kilovolts or less located within the Commonwealth, (v) one or more pumped hydroelectricity generation and storage facilities that utilize on-site or off-site renewable energy resources as all or a portion of their power source and such facilities and associated resources are located in the coalfield region of the Commonwealth as described in § 15.2-6002, regardless of whether such facility is located within or without the utility's service territory, or (vi) one or more electric distribution grid transformation projects; however, subject to the provisions of the following sentence, the utility shall not file a petition under clause (iv) more often than annually and, in such petition, shall not seek any annual incremental increase in the level of investments associated with such a petition that exceeds five percent of such utility's distribution rate base, as such rate base was determined for the most recently ended 12-month test period in the utility's latest review proceeding conducted pursuant to subdivision 3 and concluded by final order of the Commission prior to the date of filing of such petition under clause (iv). In all proceedings regarding petitions filed under clause (iv) or (vi), the level of investments approved for recovery in such proceedings shall be in addition to, and not in lieu of, levels of investments previously approved for recovery in prior proceedings under clause (iv) or (vi), as applicable. As of December 1, 2028, any costs recovered by a utility pursuant to clause (iv) shall be limited to any remaining costs associated with conversions of overhead distribution facilities to underground facilities that have been previously approved or are pending approval by the Commission through a petition by the utility under this subdivision. Such a petition concerning facilities described in clause (ii) that utilize nuclear power, facilities described in clause (ii) that are coal-fueled and will be built by a Phase I Utility, or facilities described in clause (i) may also be filed before the expiration or termination of capped rates. A utility that constructs or makes modifications to any such facility, or purchases any facility consisting of at least one megawatt of generating capacity using energy derived from sunlight and located in the Commonwealth and that utilizes goods or services sourced, in whole or in part, from one or more Virginia businesses, shall have the right to recover the costs of the facility, as accrued against income, through its rates, including projected construction work in progress, and any associated allowance for funds used during construction, planning, development and construction or acquisition costs, life-cycle costs, costs related to assessing the feasibility of potential sites for new underground facilities, and costs of infrastructure associated therewith, plus, as an incentive to undertake such projects, an enhanced rate of return on common equity calculated as specified below; however, in determining the amounts recoverable under a rate adjustment clause for new underground facilities, the Commission shall not consider, or increase or reduce such amounts recoverable because of (a) the operation and maintenance costs attributable to either the overhead distribution facilities being replaced or the new underground facilities or (b) any other costs attributable to the overhead distribution facilities being replaced. Notwithstanding the preceding sentence, the costs described in clauses (a) and (b) thereof shall remain eligible for recovery from customers through the utility's base rates for distribution service. A utility filing a petition for approval to construct or purchase a facility consisting of at least one megawatt of generating capacity using energy derived from sunlight and located in the Commonwealth and that utilizes goods or services sourced, in whole or in part, from one or more Virginia businesses may propose a rate adjustment clause based on a market index in lieu of a cost of service model for such facility. A utility seeking approval to construct or purchase a generating facility that emits carbon dioxide shall demonstrate that it has already met the energy savings goals identified in § 56-596.2 and that the identified need cannot be met more affordably through the deployment or utilization of demand-side resources or energy storage resources and that it has considered and weighed alternative options, including third-party market alternatives, in its selection process.
The costs of the facility, other than return on projected construction work in progress and allowance for funds used during construction, shall not be recovered prior to the date a facility constructed by the utility and described in clause (i), (ii), (iii), or (v) begins commercial operation, the date the utility becomes the owner of a purchased generation facility consisting of at least one megawatt of generating capacity using energy derived from sunlight and located in the Commonwealth and that utilizes goods or services sourced, in whole or in part, from one or more Virginia businesses, or the date new underground facilities are classified by the utility as plant in service. In any application to construct a new generating facility, the utility shall include, and the Commission shall consider, the social cost of carbon, as determined by the Commission, as a benefit or cost, whichever is appropriate. The Commission shall ensure that the development of new, or expansion of existing, energy resources or facilities does not have a disproportionate adverse impact on historically economically disadvantaged communities. The Commission may adopt any rules it deems necessary to determine the social cost of carbon and shall use the best available science and technology, including the Technical Support Document: Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866, published by the Interagency Working Group on Social Cost of Greenhouse Gases from the United States Government in August 2016, as guidance. The Commission shall include a system to adjust the costs established in this section with inflation.
Such enhanced rate of return on common equity shall be applied to allowance for funds used during construction and to construction work in progress during the construction phase of the facility and shall thereafter be applied to the entire facility during the first portion of the service life of the facility. The first portion of the service life shall be as specified in the table below; however, the Commission shall determine the duration of the first portion of the service life of any facility, within the range specified in the table below, which determination shall be consistent with the public interest and shall reflect the Commission's determinations regarding how critical the facility may be in meeting the energy needs of the citizens of the Commonwealth and the risks involved in the development of the facility. After the first portion of the service life of the facility is concluded, the utility's general rate of return shall be applied to such facility for the remainder of its service life. As used herein, the service life of the facility shall be deemed to begin on the date a facility constructed by the utility and described in clause (i), (ii), (iii), or (v) begins commercial operation, the date the utility becomes the owner of a purchased generation facility consisting of at least one megawatt of generating capacity using energy derived from sunlight and located in the Commonwealth and that utilizes goods or services sourced, in whole or in part, from one or more Virginia businesses, or the date new underground facilities or new electric distribution grid transformation projects are classified by the utility as plant in service, and such service life shall be deemed equal in years to the life of that facility as used to calculate the utility's depreciation expense. Such enhanced rate of return on common equity shall be calculated by adding the basis points specified in the table below to the utility's general rate of return, and such enhanced rate of return shall apply only to the facility that is the subject of such rate adjustment clause. Allowance for funds used during construction shall be calculated for any such facility utilizing the utility's actual capital structure and overall cost of capital, including an enhanced rate of return on common equity as determined pursuant to this subdivision, until such construction work in progress is included in rates. The construction of any facility described in clause (i) or (v) is in the public interest, and in determining whether to approve such facility, the Commission shall liberally construe the provisions of this title. The construction or purchase by a utility of one or more generation facilities with at least one megawatt of generating capacity, and with an aggregate rated capacity that does not exceed 16,100 megawatts, including rooftop solar installations with a capacity of not less than 50 kilowatts, and with an aggregate capacity of 100 megawatts, that use energy derived from sunlight or from onshore wind and are located in the Commonwealth or off the Commonwealth's Atlantic shoreline, regardless of whether any of such facilities are located within or without the utility's service territory, is in the public interest, and in determining whether to approve such facility, the Commission shall liberally construe the provisions of this title. A utility may enter into short-term or long-term power purchase contracts for the power derived from sunlight generated by such generation facility prior to purchasing the generation facility. The replacement of any subset of a utility's existing overhead distribution tap lines that have, in the aggregate, an average of nine or more total unplanned outage events-per-mile over a preceding 10-year period with new underground facilities in order to improve electric service reliability is in the public interest. In determining whether to approve petitions for rate adjustment clauses for such new underground facilities that meet this criteria, and in determining the level of costs to be recovered thereunder, the Commission shall liberally construe the provisions of this title.
The conversion of any such facilities on or after September 1, 2016, is deemed to provide local and system-wide benefits and to be cost beneficial, and the costs associated with such new underground facilities are deemed to be reasonably and prudently incurred and, notwithstanding the provisions of subsection C or D, shall be approved for recovery by the Commission pursuant to this subdivision, provided that the total costs associated with the replacement of any subset of existing overhead distribution tap lines proposed by the utility with new underground facilities, exclusive of financing costs, shall not exceed an average cost per customer of $20,000, with such customers, including those served directly by or downline of the tap lines proposed for conversion, and, further, such total costs shall not exceed an average cost per mile of tap lines converted, exclusive of financing costs, of $750,000. A utility shall, without regard for whether it has petitioned for any rate adjustment clause pursuant to clause (vi), petition the Commission, not more than once annually, for approval of a plan for electric distribution grid transformation projects. Any plan for electric distribution grid transformation projects shall include both measures to facilitate integration of distributed energy resources and measures to enhance physical electric distribution grid reliability and security. In ruling upon such a petition, the Commission shall consider whether the utility's plan for such projects, and the projected costs associated therewith, are reasonable and prudent. Such petition shall be considered on a stand-alone basis without regard to the other costs, revenues, investments, or earnings of the utility; without regard to whether the costs associated with such projects will be recovered through a rate adjustment clause under this subdivision or through the utility's rates for generation and distribution services; and without regard to whether such costs will be the subject of a customer credit offset, as applicable, pursuant to subdivision 8 d. The Commission's final order regarding any such petition for approval of an electric distribution grid transformation plan shall be entered by the Commission not more than six months after the date of filing such petition. The Commission shall likewise enter its final order with respect to any petition by a utility for a certificate to construct and operate a generating facility or facilities utilizing energy derived from sunlight, pursuant to subsection D of § 56-580, within six months after the date of filing such petition. The basis points to be added to the utility's general rate of return to calculate the enhanced rate of return on common equity, and the first portion of that facility's service life to which such enhanced rate of return shall be applied, shall vary by type of facility, as specified in the following table:
| a | Type of Generation Facility | Basis Points | First Portion of Service Life |
| b | Nuclear-powered | 200 | Between 12 and 25 years |
| c | Carbon capture compatible, clean-coal powered | 200 | Between 10 and 20 years |
| d | Renewable powered, other than landfill gas powered | 200 | Between 5 and 15 years |
| e | Coalbed methane gas powered | 150 | Between 5 and 15 years |
| f | Landfill gas powered | 200 | Between 5 and 15 years |
| g | Conventional coal or combined-cycle combustion turbine | 100 | Between 10 and 20 years |
Only those facilities as to which a rate adjustment clause under this subdivision has been previously approved by the Commission, or as to which a petition for approval of such rate adjustment clause was filed with the Commission, on or before January 1, 2013, shall be entitled to the enhanced rate of return on common equity as specified in the above table during the construction phase of the facility and the approved first portion of its service life.
Thirty percent of all costs of such a facility utilizing nuclear power that the utility incurred between July 1, 2007, and December 31, 2013, and all of such costs incurred after December 31, 2013, may be deferred by the utility and recovered through a rate adjustment clause under this subdivision at such time as the Commission provides in an order approving such a rate adjustment clause. The remaining 70 percent of all costs of such a facility that the utility incurred between July 1, 2007, and December 31, 2013, shall not be deferred for recovery through a rate adjustment clause under this subdivision; however, such remaining 70 percent of all costs shall be recovered ratably through existing base rates as determined by the Commission in the test periods under review in the utility's next review filed after July 1, 2014. Thirty percent of all costs of a facility utilizing energy derived from offshore wind that the utility incurred between July 1, 2007, and December 31, 2013, and all of such costs incurred after December 31, 2013, may be deferred by the utility and recovered through a rate adjustment clause under this subdivision at such time as the Commission provides in an order approving such a rate adjustment clause. The remaining 70 percent of all costs of such a facility that the utility incurred between July 1, 2007, and December 31, 2013, shall not be deferred for recovery through a rate adjustment clause under this subdivision; however, such remaining 70 percent of all costs shall be recovered ratably through existing base rates as determined by the Commission in the test periods under review in the utility's next review filed after July 1, 2014.
In connection with planning to meet forecasted demand for electric generation supply and assure the adequate and sufficient reliability of service, consistent with § 56-598, planning and development activities for a new utility-owned and utility-operated generating facility or facilities utilizing energy derived from sunlight or from onshore or offshore wind are in the public interest.
Notwithstanding any provision of Chapter 296 of the Acts of Assembly of 2018, construction, purchasing, or leasing activities for a new utility-owned and utility-operated generating facility or facilities utilizing energy derived from sunlight or from onshore wind with an aggregate capacity of 16,100 megawatts, including rooftop solar installations with a capacity of not less than 50 kilowatts, and with an aggregate capacity of 100 megawatts, together with a utility-owned and utility-operated generating facility or facilities utilizing energy derived from offshore wind with an aggregate capacity of not more than 3,000 megawatts, are in the public interest. Additionally, energy storage facilities with an aggregate capacity of 2,700 megawatts are in the public interest. To the extent that a utility elects to recover the costs of any such new generation or energy storage facility or facilities through its rates for generation and distribution services and does not petition and receive approval from the Commission for recovery of such costs through a rate adjustment clause described in clause (ii), the Commission shall, upon the request of the utility in a review proceeding, provide for a customer credit reinvestment offset, as applicable, pursuant to subdivision 8 d with respect to all costs deemed reasonable and prudent by the Commission in a proceeding pursuant to subsection D of § 56-580 or in a review proceeding.
Electric distribution grid transformation projects are in the public interest. To the extent that a utility elects to recover the costs of such electric distribution grid transformation projects through its rates for generation and distribution services, and does not petition and receive approval from the Commission for recovery of such costs through a rate adjustment clause described in clause (vi), the Commission shall, upon the request of the utility in a review proceeding, provide for a customer credit reinvestment offset, as applicable, pursuant to subdivision 8 d with respect to all costs deemed reasonable and prudent by the Commission in a proceeding for approval of a plan for electric distribution grid transformation projects pursuant to subdivision 6 or in a review proceeding.
Neither generation facilities described in clause (ii) that utilize simple-cycle combustion turbines nor new underground facilities shall receive an enhanced rate of return on common equity as described herein, but instead shall receive the utility's general rate of return during the construction phase of the facility and, thereafter, for the entire service life of the facility. No rate adjustment clause for new underground facilities shall allocate costs to, or provide for the recovery of costs from, customers that are served within the large power service rate class for a Phase I Utility and the large general service rate classes for a Phase II Utility. New underground facilities are hereby declared to be ordinary extensions or improvements in the usual course of business under the provisions of § 56-265.2.
As used in this subdivision, a generation facility is (1) "coalbed methane gas powered" if the facility is fired at least 50 percent by coalbed methane gas, as such term is defined in § 45.2-1600, produced from wells located in the Commonwealth, and (2) "landfill gas powered" if the facility is fired by methane or other combustible gas produced by the anaerobic digestion or decomposition of biodegradable materials in a solid waste management facility licensed by the Waste Management Board. A landfill gas powered facility includes, in addition to the generation facility itself, the equipment used in collecting, drying, treating, and compressing the landfill gas and in transmitting the landfill gas from the solid waste management facility where it is collected to the generation facility where it is combusted.
For purposes of this subdivision, "general rate of return" means the fair combined rate of return on common equity as it is determined by the Commission for such utility pursuant to subdivision 2.
Notwithstanding any other provision of this subdivision, if the Commission finds during the triennial review conducted for a Phase II Utility in 2021 that such utility has not filed applications for all necessary federal and state regulatory approvals to construct one or more nuclear-powered or coal-fueled generation facilities that would add a total capacity of at least 1500 megawatts to the amount of the utility's generating resources as such resources existed on July 1, 2007, or that, if all such approvals have been received, that the utility has not made reasonable and good faith efforts to construct one or more such facilities that will provide such additional total capacity within a reasonable time after obtaining such approvals, then the Commission, if it finds it in the public interest, may reduce on a prospective basis any enhanced rate of return on common equity previously applied to any such facility to no less than the general rate of return for such utility and may apply no less than the utility's general rate of return to any such facility for which the utility seeks approval in the future under this subdivision.
Notwithstanding any other provision of this subdivision, if a Phase II utility obtains approval from the Commission of a rate adjustment clause pursuant to subdivision 6 associated with a test or demonstration project involving a generation facility utilizing energy from offshore wind, and such utility has not, as of July 1, 2023, commenced construction as defined for federal income tax purposes of an offshore wind generation facility or facilities with a minimum aggregate capacity of 250 megawatts, then the Commission, if it finds it in the public interest, may direct that the costs associated with any such rate adjustment clause involving said test or demonstration project shall thereafter no longer be recovered through a rate adjustment clause pursuant to subdivision 6 and shall instead be recovered through the utility's rates for generation and distribution services, with no change in such rates for generation and distribution services as a result of the combination of such costs with the other costs, revenues, and investments included in the utility's rates for generation and distribution services. Any such costs shall remain combined with the utility's other costs, revenues, and investments included in its rates for generation and distribution services until such costs are fully recovered.
7. Any petition filed pursuant to subdivision 4, 5, or 6 shall be considered by the Commission on a stand-alone basis without regard to the other costs, revenues, investments, or earnings of the utility. Any costs incurred by a utility prior to the filing of such petition, or during the consideration thereof by the Commission, that are proposed for recovery in such petition and that are related to subdivision 5 a, or that are related to facilities and projects described in clause (i) of subdivision 6, or that are related to new underground facilities described in clause (iv) of subdivision 6, shall be deferred on the books and records of the utility until the Commission's final order in the matter, or until the implementation of any applicable approved rate adjustment clauses, whichever is later. Except as otherwise provided in subdivision 6, any costs prudently incurred on or after July 1, 2007, by a utility prior to the filing of such petition, or during the consideration thereof by the Commission, that are proposed for recovery in such petition and that are related to facilities and projects described in clause (ii) or clause (iii) of subdivision 6 that utilize nuclear power, or coal-fueled facilities and projects described in clause (ii) of subdivision 6 if such coal-fueled facilities will be built by a Phase I Utility, shall be deferred on the books and records of the utility until the Commission's final order in the matter, or until the implementation of any applicable approved rate adjustment clauses, whichever is later. Any costs prudently incurred after the expiration or termination of capped rates related to other matters described in subdivision 4, 5, or 6 shall be deferred beginning only upon the expiration or termination of capped rates, provided, however, that no provision of this act shall affect the rights of any parties with respect to the rulings of the Federal Energy Regulatory Commission in PJM Interconnection LLC and Virginia Electric and Power Company, 109 F.E.R.C. P 61,012 (2004). A utility shall establish a regulatory asset for regulatory accounting and ratemaking purposes under which it shall defer its operation and maintenance costs incurred in connection with (i) the refueling of any nuclear-powered generating plant and (ii) other work at such plant normally performed during a refueling outage. The utility shall amortize such deferred costs over the refueling cycle, but in no case more than 18 months, beginning with the month in which such plant resumes operation after such refueling. The refueling cycle shall be the applicable period of time between planned refueling outages for such plant. As of January 1, 2014, such amortized costs are a component of base rates, recoverable in base rates only ratably over the refueling cycle rather than when such outages occur, and are the only nuclear refueling costs recoverable in base rates. This provision shall apply to any nuclear-powered generating plant refueling outage commencing after December 31, 2013, and the Commission shall treat the deferred and amortized costs of such regulatory asset as part of the utility's costs for the purpose of proceedings conducted (a) with respect to filings under subdivision 3 made on and after July 1, 2014, and (b) pursuant to § 56-245 or the Commission's rules governing utility rate increase applications as provided in subsection B. This provision shall not be deemed to change or reset base rates.
The Commission's final order regarding any petition filed pursuant to subdivision 4, 5, or 6 shall be entered not more than three months, eight months, and nine months, respectively, after the date of filing of such petition. If such petition is approved, the order shall direct that the applicable rate adjustment clause be applied to customers' bills not more than 60 days after the date of the order, or upon the expiration or termination of capped rates, whichever is later. At any time, the Commission may, in its discretion, for a Phase I Utility, upon petition by such a utility or upon its own initiated proceeding, direct the consolidation of any one or more subsets of rate adjustment clauses previously implemented pursuant to subdivision 5 or 6 in the interest of judicial economy, customer transparency, or other factors the Commission determines to be appropriate. Any subset of rate adjustment clauses so consolidated shall continue to be considered by the Commission without regard to the other costs, revenues, investments, or earnings of the utility and remain as a cost recovery mechanism independent from the utility's rates for generation and distribution services pursuant to § 56-585.8 and subdivisions 5 and 6, but will be combined as a single rate adjustment clause for cost recovery and review purposes. Any rate adjustment clause or subset of rate adjustment clauses so consolidated shall be named in a manner, as determined by the Commission, that reasonably informs customers as to the nature of the costs recovered by the consolidated rate adjustment clause.
At any time, the Commission may, in its discretion, for a Phase II Utility, upon petition by such a utility or upon its own initiated proceeding, direct the consolidation of any one or more subsets of rate adjustment clauses previously implemented pursuant to subdivision 5 or 6 in the interest of judicial economy, customer transparency, or other factors the Commission determines to be appropriate. Any subset of rate adjustment clauses so consolidated shall continue to be considered by the Commission without regard to the other costs, revenues, investments, or earnings of the utility and remain as a cost recovery mechanism independent from the utility's rates for generation and distribution services pursuant to this subdivision and subdivisions 5 and 6, but will be combined as a single rate adjustment clause for cost recovery and review purposes. Any rate adjustment clause or subset of rate adjustment clauses so consolidated shall be named in a manner, as determined by the Commission, that reasonably informs customers as to the nature of the costs recovered by the consolidated rate adjustment clause.
8. For a Phase I Utility in any triennial review proceeding filed on or before June 30, 2023 or for a Phase II Utility in any biennial review proceeding, for the purposes of reviewing earnings on the utility's rates for generation and distribution services, the following utility generation and distribution costs not proposed for recovery under any other subdivision of this subsection, as recorded per books by the utility for financial reporting purposes and accrued against income, shall be attributed to the test periods under review and deemed fully recovered in the period recorded: costs associated with asset impairments related to early retirement determinations made by the utility for utility generation facilities fueled by coal, natural gas, or oil or for automated meter reading electric distribution service meters; costs associated with projects necessary to comply with state or federal environmental laws, regulations, or judicial or administrative orders relating to coal combustion by-product management that the utility does not petition to recover through a rate adjustment clause pursuant to subdivision 5 e; costs associated with severe weather events; and costs associated with natural disasters. Such costs shall be deemed to have been recovered from customers through rates for generation and distribution services in effect during the test periods under review unless such costs, individually or in the aggregate, together with the utility's other costs, revenues, and investments to be recovered through rates for generation and distribution services, result in the utility's earned return on its generation and distribution services for the combined test periods under review to fall more than 50 basis points below the fair combined rate of return authorized under subdivision 2 for such periods or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, to fall more than 70 basis points below the fair combined rate of return authorized under subdivision 2 for such periods. In such cases, the Commission shall, in such review proceeding, authorize deferred recovery of such costs and allow the utility to amortize and recover such deferred costs over future periods as determined by the Commission. The aggregate amount of such deferred costs shall not exceed an amount that would, together with the utility's other costs, revenues, and investments to be recovered through rates for generation and distribution services, cause the utility's earned return on its generation and distribution services to exceed the fair rate of return authorized under subdivision 2, less 50 basis points, for the combined test periods under review or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, to exceed the fair rate of return authorized under subdivision 2 less 70 basis points. Notwithstanding the prior sentence, the aggregate amount of actual and reasonable costs associated with severe weather events eligible for such deferral shall not exceed an amount that would, together with the utility's other costs, revenues, and investments to be recovered through rates for generation and distribution services, cause the utility's earned return on its generation and distribution services to exceed the fair rate of return authorized for the combined test periods under review. For the purposes of determining any amount of costs that are associated with severe weather events, the Commission shall consider nationally recognized standards such as those published by the Institute of Electrical and Electronics Engineers (IEEE). Nothing in this section shall limit the Commission's authority, pursuant to the provisions of Chapter 10 (§ 56-232 et seq.), including specifically § 56-235.2, following the review of combined test period earnings of the utility in a review, for normalization of nonrecurring test period costs and annualized adjustments for future costs, in determining any appropriate increase or decrease in the utility's rates for generation and distribution services pursuant to subdivision 8 a or 8 c.
If the Commission determines as a result of any triennial review initiated prior to July 1, 2023 that:
a. Revenue reductions related to energy efficiency measures or programs approved and deployed since the utility's previous triennial review have caused the utility, as verified by the Commission, during the test period or periods under review, considered as a whole, to earn more than 50 basis points below a fair combined rate of return on its generation and distribution services or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, more than 70 basis points below a fair combined rate of return on its generation and distribution services, as determined in subdivision 2, without regard to any return on common equity or other matters determined with respect to facilities described in subdivision 6, the Commission shall order increases to the utility's rates for generation and distribution services necessary to recover such revenue reductions. If the Commission finds, for reasons other than revenue reductions related to energy efficiency measures, that the utility has, during the test period or periods under review, considered as a whole, earned more than 50 basis points below a fair combined rate of return on its generation and distribution services or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, more than 70 basis points below a fair combined rate of return on its generation and distribution services, as determined in subdivision 2, without regard to any return on common equity or other matters determined with respect to facilities described in subdivision 6, the Commission shall order increases to the utility's rates necessary to provide the opportunity to fully recover the costs of providing the utility's services and to earn not less than such fair combined rate of return, using the most recently ended 12-month test period as the basis for determining the amount of the rate increase necessary. However, in the first triennial review proceeding conducted after January 1, 2021, for a Phase II Utility, the Commission may not order a rate increase, and in all triennial reviews of a Phase I or Phase II utility, the Commission may not order such rate increase unless it finds that the resulting rates are necessary to provide the utility with the opportunity to fully recover its costs of providing its services and to earn not less than a fair combined rate of return on both its generation and distribution services, as determined in subdivision 2, without regard to any return on common equity or other matters determined with respect to facilities described in subdivision 6, using the most recently ended 12-month test period as the basis for determining the permissibility of any rate increase under the standards of this sentence, and the amount thereof; and provided that, solely in connection with making its determination concerning the necessity for such a rate increase or the amount thereof, the Commission shall, in any triennial review proceeding conducted prior to July 1, 2028, exclude from this most recently ended 12-month test period any remaining investment levels associated with a prior customer credit reinvestment offset pursuant to subdivision d.
b. The utility has, during the test period or test periods under review, considered as a whole, earned more than 50 basis points above a fair combined rate of return on its generation and distribution services or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, more than 70 basis points above a fair combined rate of return on its generation and distribution services, as determined in subdivision 2, without regard to any return on common equity or other matters determined with respect to facilities described in subdivision 6, the Commission shall, subject to the provisions of subdivisions 8 d and 9, direct that 60 percent of the amount of such earnings that were more than 50 basis points, or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, that 70 percent of the amount of such earnings that were more than 70 basis points, above such fair combined rate of return for the test period or periods under review, considered as a whole, shall be credited to customers' bills. Any such credits shall be amortized over a period of six to 12 months, as determined at the discretion of the Commission, following the effective date of the Commission's order, and shall be allocated among customer classes such that the relationship between the specific customer class rates of return to the overall target rate of return will have the same relationship as the last approved allocation of revenues used to design base rates; or
c. The utility has, during the test period or test periods under review, considered as a whole, earned more than 50 basis points above a fair combined rate of return on its generation and distribution services or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, more than 70 basis points above a fair combined rate of return on its generation and distribution services, as determined in subdivision 2, without regard to any return on common equity or other matter determined with respect to facilities described in subdivision 6, and the combined aggregate level of capital investment that the Commission has approved other than those capital investments that the Commission has approved for recovery pursuant to a rate adjustment clause pursuant to subdivision 6 made by the utility during the test periods under review in that triennial review proceeding in new utility-owned generation facilities utilizing energy derived from sunlight, or from wind, and in electric distribution grid transformation projects, as determined pursuant to subdivision 8 d, does not equal or exceed 100 percent of the earnings that are more than 70 basis points above the utility's fair combined rate of return on its generation and distribution services for the combined test periods under review in that triennial review proceeding, the Commission shall, subject to the provisions of subdivision 10 and in addition to the actions authorized in subdivision b, also order reductions to the utility's rates it finds appropriate. However, in the first triennial review proceeding conducted after January 1, 2021, for a Phase II Utility, any reduction to the utility's rates ordered by the Commission pursuant to this subdivision shall not exceed $50 million in annual revenues, with any reduction allocated to the utility's rates for generation services, and in each triennial review of a Phase I or Phase II Utility, the Commission may not order such rate reduction unless it finds that the resulting rates will provide the utility with the opportunity to fully recover its costs of providing its services and to earn not less than a fair combined rate of return on its generation and distribution services, as determined in subdivision 2, without regard to any return on common equity or other matters determined with respect to facilities described in subdivision 6, using the most recently ended 12-month test period as the basis for determining the permissibility of any rate reduction under the standards of this sentence, and the amount thereof; and
d. (Expires July 1, 2028) In any review proceeding conducted after December 31, 2017, upon the request of the utility, the Commission shall determine, prior to directing that 70 percent of earnings that are more than 70 basis points above the utility's fair combined rate of return on its generation and distribution services for the test period or periods under review be credited to customer bills pursuant to subdivision 8 b, the aggregate level of prior capital investment that the Commission has approved other than those capital investments that the Commission has approved for recovery pursuant to a rate adjustment clause pursuant to subdivision 6 made by the utility during the test period or periods under review in both (i) new utility-owned generation facilities utilizing energy derived from sunlight, or from onshore or offshore wind, and (ii) electric distribution grid transformation projects, as determined by the utility's plant in service and construction work in progress balances related to such investments as recorded per books by the utility for financial reporting purposes as of the end of the most recent test period under review. Any such combined capital investment amounts shall offset any customer bill credit amounts, on a dollar for dollar basis, up to the aggregate level of invested or committed capital under clauses (i) and (ii). The aggregate level of qualifying invested or committed capital under clauses (i) and (ii) is referred to in this subdivision as the customer credit reinvestment offset, which offsets the customer bill credit amount that the utility has invested or will invest in new solar or wind generation facilities or electric distribution grid transformation projects for the benefit of customers, in amounts up to 100 percent of earnings that are more than 70 basis points above the utility's fair rate of return on its generation and distribution services, and thereby reduce or eliminate otherwise incremental rate adjustment clause charges and increases to customer bills, which is deemed to be in the public interest. If 100 percent of the amount of earnings that are more than 70 basis points above the utility's fair combined rate of return on its generation and distribution services, as determined in subdivision 2, exceeds the aggregate level of invested capital in new utility-owned generation facilities utilizing energy derived from sunlight, or from wind, and electric distribution grid transformation projects, as provided in clauses (i) and (ii), during the test period or periods under review, then 70 percent of the amount of such excess shall be credited to customer bills as provided in subdivision 8 b in connection with the review proceeding. The portion of any costs associated with new utility-owned generation facilities utilizing energy derived from sunlight, or from wind, or electric distribution grid transformation projects that is the subject of any customer credit reinvestment offset pursuant to this subdivision shall not thereafter be recovered through the utility's rates for generation and distribution services over the service life of such facilities and shall not thereafter be included in the utility's costs, revenues, and investments in future review proceedings conducted pursuant to subdivision 2 and shall not be the subject of a rate adjustment clause petition pursuant to subdivision 6. The portion of any costs associated with new utility-owned generation facilities utilizing energy derived from sunlight, or from wind, or electric distribution grid transformation projects that is not the subject of any customer credit reinvestment offset pursuant to this subdivision may be recovered through the utility's rates for generation and distribution services over the service life of such facilities and shall be included in the utility's costs, revenues, and investments in future review proceedings conducted pursuant to subdivision 2 until such costs are fully recovered, and if such costs are recovered through the utility's rates for generation and distribution services, they shall not be the subject of a rate adjustment clause petition pursuant to subdivision 6. Only the portion of such costs of new utility-owned generation facilities utilizing energy derived from sunlight, or from wind, or electric distribution grid transformation projects that has not been included in any customer credit reinvestment offset pursuant to this subdivision, and not otherwise recovered through the utility's rates for generation and distribution services, may be the subject of a rate adjustment clause petition by the utility pursuant to subdivision 6.
e. In any biennial review of a Phase II Utility, the Commission's final order regarding such review shall be entered not more than eight months after the date of filing, and any revisions in rates or credits so ordered shall take effect not more than 60 days after the date of the order. The fair combined rate of return on common equity determined pursuant to subdivision 2 in such review shall apply, for purposes of reviewing the utility's earnings on its rates for generation and distribution services, to the entire two or three, as applicable, successive 12-month test periods ending December 31 immediately preceding the year of the utility's subsequent review filing under subdivision 3 and shall apply to applicable rate adjustment clauses under subdivisions 5 and 6 prospectively from the date the Commission's final order in the review proceeding, utilizing rate adjustment clause true-up protocols as the Commission in its discretion may determine.
9. a. In any biennial review for a Phase II Utility filed on or prior to December 31, 2023, if the Commission determines that the utility has during the test period or test periods under review, considered as a whole, earned more than 70 basis points above a fair combined rate of return on its generation and distribution services previously authorized by the Commission, as determined in subdivision 2, without regard to any return on common equity or other matters determined with respect to facilities described in subdivision 6, which have not been combined with the utility's costs, revenues, and investments for generation and distribution services, the Commission shall direct that 85 percent of the amount of such earnings that were more than 70 basis points above such fair combined rate of return for the test period or periods under review, considered as a whole, be credited to customers' bills. Any such credits shall be amortized over a period of six to 12 months, as determined at the discretion of the Commission, following the effective date of the Commission's order, and shall be allocated among customer classes such that the relationship between the specific customer class rates of return to the overall target rate of return will have the same relationship as the last approved allocation of revenues used to design base rates.
b. In any biennial review for a Phase II Utility filed on or after January 1, 2024, if the Commission determines that the utility has during the test period or test periods under review, considered as a whole, earned above its fair combined rate of return on its generation and distribution services previously authorized by the Commission, as determined in subdivision 2, without regard to any return on common equity or other matters determined with respect to facilities described in subdivision 6, which have not been combined with the utility's costs, revenues, and investments for generation and distribution services, the Commission shall direct that 85 percent of the amount of such earnings above such fair combined rate of return for the test period or periods under review, considered as a whole, be credited to customers' bills. Further, if the Commission determines that during the test period or test periods under review, considered as a whole, a Phase II Utility earned more than 150 basis points above a fair combined rate of return on its generation and distribution services previously authorized by the Commission, without regard to any return on common equity or other matters determined with respect to facilities described in subdivision 6, which have not been combined with the utility's costs, revenues, and investments for generation and distribution services, the Commission shall direct that all such earnings that were more than 150 basis points above such fair combined rate of return for the test period or periods under review, considered as a whole, be credited to customers' bills. Any such credits shall be amortized over a period of six to 12 months, as determined at the discretion of the Commission, following the effective date of the Commission's order, and shall be allocated among customer classes such that the relationship between the specific customer class rates of return to the overall target rate of return will have the same relationship as the last approved allocation of revenues used to design base rates.
10. If, as a result of a triennial review required under this subsection and conducted with respect to any test period or periods under review ending later than December 31, 2010 (or, if the Commission has elected to stagger its biennial reviews of utilities as provided in subdivision 1, under review ending later than December 31, 2010, for a Phase I Utility, or December 31, 2011, for a Phase II Utility), the Commission finds, with respect to such test period or periods considered as a whole, that (i) any utility has, during the test period or periods under review, considered as a whole, earned more than 50 basis points above a fair combined rate of return on its generation and distribution services or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, more than 70 basis points above a fair combined rate of return on its generation and distribution services, as determined in subdivision 2, without regard to any return on common equity or other matters determined with respect to facilities described in subdivision 6, and (ii) the total aggregate regulated rates of such utility at the end of the most recently ended 12-month test period exceeded the annual increases in the United States Average Consumer Price Index for all items, all urban consumers (CPI-U), as published by the Bureau of Labor Statistics of the United States Department of Labor, compounded annually, when compared to the total aggregate regulated rates of such utility as determined pursuant to the review conducted for the base period, the Commission shall, unless it finds that such action is not in the public interest or that the provisions of subdivisions 8 b and c are more consistent with the public interest, direct that any or all earnings for such test period or periods under review, considered as a whole that were more than 50 basis points, or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, more than 70 basis points, above such fair combined rate of return shall be credited to customers' bills, in lieu of the provisions of subdivisions 8 b and c, provided that no credits shall be provided pursuant to this subdivision in connection with any triennial review unless such bill credits would be payable pursuant to the provisions of subdivision 8 d, and any credits under this subdivision shall be calculated net of any customer credit reinvestment offset amounts under subdivision 8 d. Any such credits shall be amortized and allocated among customer classes in the manner provided by subdivision 8 b. For purposes of this subdivision:
"Base period" means (i) the test period ending December 31, 2010 (or, if the Commission has elected to stagger its biennial reviews of utilities as provided in subdivision 1, the test period ending December 31, 2010, for a Phase I Utility, or December 31, 2011, for a Phase II Utility), or (ii) the most recent test period with respect to which credits have been applied to customers' bills under the provisions of this subdivision, whichever is later.
"Total aggregate regulated rates" shall include: (i) fuel tariffs approved pursuant to § 56-249.6, except for any increases in fuel tariffs deferred by the Commission for recovery in periods after December 31, 2010, pursuant to the provisions of clause (ii) of subsection C of § 56-249.6; (ii) rate adjustment clauses implemented pursuant to subdivision 4 or 5; (iii) revisions to the utility's rates pursuant to subdivision 8 a; (iv) revisions to the utility's rates pursuant to the Commission's rules governing utility rate increase applications, as permitted by subsection B, occurring after July 1, 2009; and (v) base rates in effect as of July 1, 2009.
11. For purposes of this section, the Commission shall regulate the rates, terms and conditions of any utility subject to this section on a stand-alone basis utilizing the actual end-of-test period capital structure and cost of capital of such utility, excluding any debt associated with securitized bonds that are the obligation of non-Virginia jurisdictional customers, unless the Commission finds that the debt to equity ratio of such capital structure is unreasonable for such utility, in which case the Commission may utilize a debt to equity ratio that it finds to be reasonable for such utility in determining any rate adjustment pursuant to subdivisions 8 a and c, and without regard to the cost of capital, capital structure, revenues, expenses or investments of any other entity with which such utility may be affiliated. In particular, and without limitation, the Commission shall determine the federal and state income tax costs for any such utility that is part of a publicly traded, consolidated group as follows: (i) such utility's apportioned state income tax costs shall be calculated according to the applicable statutory rate, as if the utility had not filed a consolidated return with its affiliates, and (ii) such utility's federal income tax costs shall be calculated according to the applicable federal income tax rate and shall exclude any consolidated tax liability or benefit adjustments originating from any taxable income or loss of its affiliates.
B. Nothing in this section shall preclude an investor-owned incumbent electric utility from applying for an increase in rates pursuant to § 56-245 or the Commission's rules governing utility rate increase applications; however, in any such filing, a fair rate of return on common equity shall be determined pursuant to subdivision A 2. Nothing in this section shall preclude such utility's recovery of fuel and purchased power costs as provided in § 56-249.6.
C. Except as otherwise provided in this section, the Commission shall exercise authority over the rates, terms and conditions of investor-owned incumbent electric utilities for the provision of generation, transmission and distribution services to retail customers in the Commonwealth pursuant to the provisions of Chapter 10 (§ 56-232 et seq.), including specifically § 56-235.2.
D. The Commission may determine, during any proceeding authorized or required by this section, the reasonableness or prudence of any cost incurred or projected to be incurred, by a utility in connection with the subject of the proceeding. A determination of the Commission regarding the reasonableness or prudence of any such cost shall be consistent with the Commission's authority to determine the reasonableness or prudence of costs in proceedings pursuant to the provisions of Chapter 10 (§ 56-232 et seq.). In determining the reasonableness or prudence of a utility providing energy and capacity to its customers from renewable energy resources, the Commission shall consider the extent to which such renewable energy resources, whether utility-owned or by contract, further the objectives of the Commonwealth Clean Energy Policy set forth in § 45.2-1706.1, and shall also consider whether the costs of such resources is likely to result in unreasonable increases in rates paid by customers.
E. Notwithstanding any other provision of law, the Commission shall determine the amortization period for recovery of any appropriate costs due to the early retirement of any electric generation facilities owned or operated by any Phase I Utility or Phase II Utility. In making such determination, the Commission shall (i) perform an independent analysis of the remaining undepreciated capital costs; (ii) establish a recovery period that best serves ratepayers; and (iii) allow for the recovery of any carrying costs that the Commission deems appropriate.
F. The Commission shall include in its report required by subsection B of § 56-596 any information concerning the reliability impacts of generation unit additions and retirement determinations by a Phase I or Phase II Utility, along with the potential impact on the purchase of power from generation assets outside the Virginia jurisdiction used to serve the utility's native load, utilizing information from the respective utility's integrated resource plan or information from the respective utility's plan filed pursuant to subsection D of § 56-585.5.
G. The Commission shall promulgate such rules and regulations as may be necessary to implement the provisions of this section.
2007, cc. 888, 933; 2008, c. 476; 2009, c. 824; 2011, cc. 236, 367, 371, 380, 382; 2012, c. 435; 2013, c. 2; 2014, cc. 212, 541, 548, 550; 2015, cc. 37, 599; 2016, c. 3; 2017, cc. 246, 564, 583, 820; 2018, cc. 296, 795; 2019, cc. 535, 741, 773; 2020, cc. 662, 799, 801, 1108, 1190, 1193, 1194; 2021, Sp. Sess. I, c. 327; 2023, cc. 704, 705, 749, 757, 775, 776.
A. No biennial reviews of the rates, terms, and conditions for any service of a Phase I Utility, as defined in § 56-585.1, shall be conducted at any time by the Commission for the three successive 12-month test periods beginning January 1, 2014, and ending December 31, 2016. No biennial reviews of the rates, terms, and conditions for any service of a Phase II Utility, as defined in § 56-585.1, shall be conducted at any time by the Commission for the two successive 12-month test periods beginning January 1, 2015, and ending December 31, 2016. Such test periods beginning January 1, 2014, and ending December 31, 2017, for a Phase I Utility, and beginning January 1, 2015, and ending December 31, 2016, for a Phase II Utility, are collectively referred to herein as the "Transitional Rate Period." Review of recovery of fuel and purchase power costs shall continue during the Transitional Rate Period in accordance with § 56-249.6. Any biennial review of the rates, terms, and conditions for any service of a Phase II Utility occurring in 2015 during the Transitional Rate Period shall be solely a review of the utility's earnings on its rates for generation and distribution services for the two 12-month test periods ending December 31, 2014, and a determination of whether any credits to customers are due for such test periods pursuant to subdivision A 8 b of § 56-585.1. After the conclusion of the Transitional Rate Period, reviews of the utility's rates for generation and distribution services shall resume for a Phase I Utility in 2020, with the first such proceeding utilizing the three successive 12-month test periods beginning January 1, 2017, and ending December 31, 2019. After the conclusion of the Transitional Rate Period, reviews of the utility's rates for generation and distribution services shall resume for a Phase II Utility in 2021, with the first such proceeding utilizing the four successive 12-month test periods beginning January 1, 2017, and ending December 31, 2020. Consistent with this provision, (i) no biennial review filings shall be made by an investor-owned incumbent electric utility in the years 2016 through 2019, inclusive, and (ii) no adjustment to an investor-owned incumbent electric utility's existing tariff rates, including any rates adopted pursuant to § 56-235.2, shall be made between the beginning of the Transitional Rate Period and the conclusion of the first review after the conclusion of the Transitional Rate Period, except as may be provided pursuant to § 56-245 or 56-249.6 or subdivisions A 4, 5, or 6 of § 56-585.1.
B. During the Transitional Rate Period, pursuant to § 56-36, the Commission shall have the right at all times to inspect the books, papers and documents of any investor-owned incumbent electric utility and to require from such companies, from time to time, special reports and statements, under oath, concerning their business.
C. 1. Commencing in 2016 and concluding in 2018, the State Corporation Commission, after notice and opportunity for a hearing, shall conduct a proceeding every two years to determine the fair rate of return on common equity to be used by a Phase I Utility as the general rate of return applicable to rate adjustment clauses under subdivisions A 5 or A 6 of § 56-585.1. A Phase I Utility's filing in such proceedings shall be made on or before March 31 of 2016, and 2018.
2. Commencing in 2017 and concluding in 2019, the State Corporation Commission, after notice and opportunity for a hearing, shall conduct a proceeding every two years to determine the fair rate of return on common equity to be used by a Phase II Utility as the general rate of return applicable to rate adjustment clauses under subdivisions A 5 or A 6 of § 56-585.1. A Phase II utility's filing in such proceedings shall be made on or before March 31 of 2017 and 2019.
3. Such fair rate of return shall be calculated pursuant to the methodology set forth in subdivisions A 2 a and b of § 56-585.1 and shall utilize the utility's actual end-of-test-period capital structure and cost of capital, as well as a 12-month test period ending December 31 immediately preceding the year in which the proceeding is conducted. The Commission's final order in such a proceeding shall be entered no later than eight months after the date of filing, with any adjustment to the fair rate of return for applicable rate adjustment clauses under subdivisions A 5 and 6 of § 56-585.1 taking effect on the date of the Commission's final order in the proceeding, utilizing rate adjustment clause true-up protocols as the Commission may in its discretion determine. Such proceeding shall concern only the issue of the determination of such fair rate of return to be used for rate adjustment clauses under subdivisions A 5 and 6 of § 56-585.1, and such determination shall have no effect on rates other than those applicable to such rate adjustment clauses; however, after the final such proceeding for a utility has been concluded, the fair combined rate of return on common equity so determined therein shall also be deemed equal to the fair combined rate of return on common equity to be used in such utility's first review proceeding conducted after the end of the utility's Transitional Rate Period to review such utility's earnings on its rates for generation and distribution services for the historic test periods.
D. In furtherance of rate stability during the Transitional Rate Period, any Phase II Utility carrying a prior period deferred fuel expense recovery balance on its books and records as of December 31, 2014, shall not recover from customers 50 percent of any such balance outstanding as of December 31, 2014, and the State Corporation Commission shall implement as soon as practicable reductions in the fuel factor rate of any such Phase II Utility to reflect the nonrecovery of any such fuel expense as well as any reduction in the fuel factor associated with the Phase II Utility's current period forecasted fuel expense over recovery for the 2014-2015 fuel year and projected fuel expense for the 2015-2016 fuel year.
E. Except for early retirement plans identified by the utility in an integrated resource plan filed with the State Corporation Commission by September 1, 2014, for utility generation plants, an investor-owned incumbent electric utility shall not permanently retire an electric power generation facility from service during the Transitional Rate Period without first obtaining the approval of the State Corporation Commission, upon petition from such investor-owned incumbent electric utility, and a finding by the State Corporation Commission that the retirement determination is reasonable and prudent. During the Transitional Rate Period, an investor-owned incumbent electric utility shall recover the following costs, as recorded per books by the utility for financial reporting purposes and accrued against income, only through its existing tariff rates for generation or distribution services, except such costs as may be recovered pursuant to § 56-245, § 56-249.6 or subdivisions A 4, A 5, or A 6 of § 56-585.1: (i) costs associated with asset impairments related to early retirement determinations for utility generation facilities resulting from the implementation of carbon emission guidelines for existing electric power generation facilities that the U.S. Environmental Protection Agency has issued pursuant to § 111(d) of the Clean Air Act; (ii) costs associated with severe weather events; and (iii) costs associated with natural disasters.
F. During the Transitional Rate Period:
1. The State Corporation Commission shall submit a report and make recommendations to the Governor and the General Assembly annually on or before December 1 of each year assessing the updated integrated resource plan of any investor-owned incumbent electric utility. The report shall include an analysis of, among other matters, the amount, reliability, and type of generation facilities needed to serve Virginia native load compared to what is then available to serve such load and what may be available to serve such load in the future in view of market conditions and current and pending state and federal environmental regulations. As a part of such report, the State Corporation Commission shall update its estimate of the impact upon electric rates in Virginia of the implementation of carbon emission guidelines for existing electric power generation facilities that the U.S. Environmental Protection Agency has issued pursuant to § 111(d) of the federal Clean Air Act. The State Corporation Commission shall submit copies of such annual reports to the Chairman of the House Committee on Labor and Commerce, the Chairman of the Senate Committee on Commerce and Labor and the Chairman of the Commission on Electric Utility Regulation; and
2. The Department of Environmental Quality shall submit a report and make recommendations to the Governor and the General Assembly annually on or before December 1 of each year concerning the implementation of carbon emission guidelines for existing electric power generation facilities that the U.S. Environmental Protection Agency has issued pursuant to § 111(d) of the federal Clean Air Act. The report shall include an analysis of, among other matters, the impact of such federal regulations on the operation of any investor-owned incumbent electric utility's electric power generation facilities and any changes, interdiction, or suspension of such regulations. The Department of Environmental Quality shall submit copies of such annual reports to the Chairman of the House Committee on Labor and Commerce, the Chairman of the Senate Committee on Commerce and Labor and the Chairman of the Commission on Electric Utility Regulation.
G. The construction or purchase by an investor-owned incumbent utility of one or more generation facilities with at least one megawatt of generating capacity, and with an aggregate rated capacity that does not exceed 5,000 megawatts, including rooftop solar installations with a capacity of not less than 50 kilowatts, and with an aggregate capacity of 50 megawatts, that use energy derived from sunlight or from wind and are located in the Commonwealth or off the Commonwealth's Atlantic shoreline, regardless of whether any of such facilities are located within or without such utility's service territory, is in the public interest, and in determining whether to approve such facility, the Commission shall liberally construe the provisions of this section. Such utility shall utilize goods or services sourced, in whole or in part, from one or more Virginia businesses. The utility may propose a rate adjustment clause based on a market index in lieu of a cost of service model for such facility. An investor-owned incumbent utility may enter into short-term or long-term power purchase contracts for the power derived from sunlight generated by such generation facility prior to purchasing the generation facility.
H. To the extent that the provisions of this section are inconsistent with the provisions of §§ 56-249.6 and 56-585.1, the provisions of this section shall control.
Notwithstanding the provisions of §§ 56-249.6 and 56-585.1:
Each Phase I and II Utility shall conduct a pilot program for energy assistance and weatherization for low income, elderly, and disabled individuals in their respective service territories in the Commonwealth. Each pilot program shall be funded by the utility and shall commence September 1, 2015. Each Phase I Utility shall continue such pilot program at no less than the existing levels of funding as of July 1, 2018, for each year that the utility provides such service. Each Phase II Utility shall continue such pilot program at no less than $13 million for each year the utility is providing such service. The funding for the pilot programs established pursuant hereto for energy assistance and weatherization for low-income, elderly, and disabled individuals in the service territory in the Commonwealth of each respective utility shall continue until the earlier of amendment or repeal of this section or July 1, 2028. Each such utility shall report on the status of its pilot program, including the number of individuals served thereby, to the Governor, the State Corporation Commission, and the Chairman of the House Committee on Labor and Commerce and the Chairman of the Senate Committee on Commerce and Labor by July 1, 2016, and each year thereafter.
A. As used in this section:
"Eligible generation facility" means an electrical generation facility that:
1. Exclusively uses energy derived from sunlight;
2. Is placed in service on or after July 1, 2017;
3. Is not constructed by an investor-owned utility and either (i) is acquired by an investor-owned utility through an asset purchase agreement or (ii) is subject to a power purchase agreement under which an investor-owned utility purchases the facility's output from a third party; and
4. Has a generating capacity of:
a. Not more than two megawatts; or
b. More than two megawatts if not more than two megawatts of the output from the electrical generation facility is selected in an investor-owned utility's RFP for dedication to its pilot program.
"Generating capacity" means an electrical generation facility's nameplate rated capacity measured in direct current megawatts.
"Investor-owned utility" means an electric utility that is a Phase I Utility or a Phase II Utility.
"Low-income community" means a census tract within the Commonwealth designated by the U.S. Department of Housing and Urban Development in 2019 or any year thereafter as a qualified census tract for purposes of the Low-Income Housing Tax Credit pursuant to § 42 of the Internal Revenue Code.
"Participating generating facility" means an eligible generation facility that is selected by an investor-owned utility through its RFP for inclusion in its pilot program.
"Participating third party" means, for investor-owned utilities, a Virginia nonresidential-class customer, an affiliate, a solar development entity, or a nonjurisdictional customer that takes on the obligation, as part of a variable-output contract, of pilot program costs not recovered through the voluntary companion rate schedule as specified in subdivision B 8.
"Participating utility" means (i) each investor-owned utility and (ii) any utility consumer services cooperative that elects to conduct a pilot program under subsection C.
"Phase I Utility" means an investor-owned incumbent electric utility that was, as of July 1, 1999, not bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002.
"Phase II Utility" means an investor-owned incumbent electric utility that was, as of July 1, 1999, bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002.
"Pilot program" means a community solar pilot program conducted by a participating utility pursuant to this section following approval by the Commission, under which the participating utility sells electric power to subscribing customers under a voluntary companion rate schedule and the participating utility generates or purchases electric power from participating generation facilities selected by the participating utility.
"Pilot program costs" means all of a participating utility's identified, projected, and actual costs of its pilot program, including costs for (i) purchased power; (ii) renewable and other environmental attributes; (iii) transmission and distribution services; (iv) generating capacity and energy balancing; (v) RFP process costs; (vi) administrative and marketing charges; (vii) capital costs and operations and maintenance expenses related to building, owning, and operating eligible generating facilities; and (viii) a reasonable margin, which margin shall be the weighted average cost of capital.
"Pilot program period" means the three-year period ending three years following the date the first subscription is entered into by a customer.
"RFP" means the request for proposal process conducted by an investor-owned utility.
"Small eligible generation facility" means an eligible generation facility with a generating capacity of less than 0.5 megawatt.
"Solar development entity" means a business entity organized primarily for the purpose of proposing, developing, constructing, purchasing, or selling at wholesale all or part of the output of an eligible generation facility. A solar development entity may be organized in any form and may be a special purpose entity.
"Utility aggregation cooperative" has the same meaning ascribed to "cooperative" in § 56-231.38.
"Utility consumer services cooperative" has the same meaning ascribed to "cooperative" in § 56-231.15.
"Voluntary companion rate schedule" means a rate schedule approved by the Commission upon application by a participating utility that provides for the recovery of the pilot program costs by the participating utility.
B. Notwithstanding the provisions of subsection B of § 56-234 and §§ 56-249.6 and 56-585.1, each investor-owned utility shall conduct a pilot program for retail customers as follows:
1. Each investor-owned utility shall design its own pilot program and within six months of receiving Commission approval shall make subscriptions for participation in its pilot program available to its retail customers on a voluntary basis.
2. An investor-owned utility shall select eligible generating facilities for dedication to its pilot program through an RFP process, under which process:
a. Each investor-owned utility shall have issued one or more public RFPs for eligible generating facilities and the purchase of all energy output and associated renewable energy certificates and other environmental attributes.
b. Each RFP shall:
(1) State the price and non-price criteria used by the investor-owned utility in selecting proposals for dedication to its pilot program; and
(2) Require as a criterion for selection that eligible generating facilities with a combined generating capacity of not less than two megawatts, and any eligible generating facility with a generating capacity of more than two megawatts, be first placed in service on or after July 1, 2017.
c. Each investor-owned utility is authorized to select, under an asset purchase or power purchase agreement, small eligible generating facilities for dedication to its pilot program without regard to whether price criteria are satisfied by their selection if the selection of the small eligible generating facilities (i) materially advances non-price criteria, including a criterion favoring geographic distribution of eligible generating facilities, provided that the generating capacity of small eligible generating facilities does not exceed 25 percent of the utility's pilot program's minimum generating capacity specified in subdivision 3, or (ii) is located in a low-income community as provided in subdivision 15.
d. An investor-owned utility shall not select through its RFP an electrical generation facility with a generating capacity of more than two megawatts for its pilot program unless (i) the costs can be appropriately documented for the portion of the facility's output, which portion shall not exceed two megawatts, that is dedicated to the pilot program and (ii) for a Phase II Utility only, the portion of the facility's generating capacity selected pursuant to this subdivision does not exceed 50 percent of the investor-owned utility's pilot program's minimum generating capacity specified in subdivision 3. The portion of the facility's generating capacity that exceeds the portion of the facility's generating capacity that is selected pursuant to this subdivision shall not be applied in determining whether the pilot program satisfies requirements of subdivision 3 regarding a pilot program's minimum generating capacity.
e. In selecting eligible generating facilities for dedication to its pilot program, an investor-owned utility shall give due consideration to relative costs, economic development benefits, and geographic diversity of eligible generating facilities and ensure that the selection of such facilities complies with the requirements of subdivision 15 regarding the location of eligible generating facilities in low-income communities.
f. The investor-owned utility's application to the Commission shall include a description of the application of the price and non-price criteria in the investor-owned utility's selection of participating generating facilities from among the proposals submitted in response to the RFP.
3. The amount of generating capacity of the eligible generating facilities in an investor-owned utility's pilot program shall not be less than (i) 0.5 megawatt if the pilot program is conducted by a Phase I Utility or (ii) 10 megawatts if the pilot program is conducted by a Phase II Utility.
4. The amount of generating capacity of the eligible generating facilities in an investor-owned utility's pilot program shall not exceed (i) 10 megawatts if the pilot program is conducted by a Phase I Utility or (ii) 40 megawatts if the pilot program is conducted by a Phase II Utility.
5. An investor-owned utility shall have the option of increasing the amount of generating capacity of the eligible generating facilities in its pilot program above the amount most recently approved by the Commission, in such increments as the investor-owned utility elects, as follows:
a. Any such increase shall not result in an amount of generating capacity that exceeds the cap specified for the investor-owned utility's pilot program under subdivision 4;
b. No such increase shall be authorized until such time that 90 percent of the amount of generating capacity of the eligible generating facilities then approved for its pilot program has been subscribed by customers through the investor-owned utility's voluntary companion rate schedule;
c. An investor-owned utility may seek any number of increases in the amount of generating capacity of the eligible generating facilities in its pilot program, subject to the conditions in subdivisions a and b; and
d. The investor-owned utility shall select eligible generating facilities for any increase in the generating capacity of its pilot program through an RFP process that complies with the requirements of subdivision 2.
6. Each pilot program shall expire at the end of its pilot program period, unless renewed or made permanent as provided in subsection G.
7. The renewable energy certificates and other environmental attributes associated with the voluntary companion rate schedule shall be retired by the investor-owned utility on the subscribing customer's behalf.
8. An investor-owned utility shall recover all its pilot program costs primarily through its voluntary companion rate schedule. However, pilot program costs that are not recovered through the voluntary companion rate schedule shall be recoverable from a participating third party and not from the investor-owned utility's Virginia jurisdictional customers. To the extent participating third parties are obligated for pilot program costs not recovered through the voluntary companion rate schedule, variable-output contracts between participating third parties other than affiliates and investor-owned utilities shall be negotiated at arm's length and shall not be reviewable by the Commission and shall require no further Commission approvals pursuant to Chapter 4 (§ 56-76 et seq.) or other applicable law.
9. At the conclusion of the pilot program period, to the extent that the pilot program is not made permanent or extended, each participating generating facility shall cease to be part of the pilot program and shall return to operation under the variable-output contract with a participating third party.
10. Any fixed generation costs and fixed purchased power costs shall remain fixed for subscribing customers throughout the duration of the subscribing customers' continuous and uninterrupted participation in the voluntary companion rate schedule. A subscribing customer's participation in the voluntary companion rate schedule shall be deemed to be continuous and uninterrupted notwithstanding a change in the location where the customer receives service if the new location continues to be within the investor-owned utility's service territory and the customer provides the investor-owned utility with notice of the change prior to or within 90 days following the change. Investor-owned utilities are authorized to decrease the generation or purchased power rate, or both, at any time to reflect cost reductions, if any, subject to Commission review. If, pursuant to subdivision 9, the pilot program is not made permanent or continued, the subscribing customers' subscriptions to the voluntary companion rate schedule shall survive the termination of the pilot program.
11. A subscribing customer's usage that exceeds the amount subscribed for under the voluntary companion rate schedule shall be billed under the customer's applicable standard rate.
12. An investor-owned utility shall not require a subscribing customer to enter an agreement or subscription for participation in a pilot program of more than 12 months' duration unless the subscribing customer's subscription exceeds 100 kW, or its equivalent in kWh, at the time the customer initially enters into the agreement or subscription.
13. As part of an arrangement with a solar development entity, a utility may enter into an agreement that provides for risk sharing and collaboration in marketing a utility's pilot program if the solar development entity is a participating third party.
14. An investor-owned utility shall have the ability to close its pilot program to new subscribers according to the terms of the voluntary companion rate schedule upon notice to the Commission. This option shall be exercisable once per year, upon the anniversary date of the Commission's order approving the voluntary companion rate schedule.
15. Notwithstanding any provision of this section to the contrary, effective July 1, 2020, an investor-owned utility shall not select an eligible generating facility that is located outside a low-income community for dedication to its pilot program unless the investor-owned utility contemporaneously selects for dedication to its pilot program one or more eligible generating facilities that are located within a low-income community and of which the pilot program costs equal or exceed the pilot program costs of the eligible generating facility that is located outside a low-income community.
C. Notwithstanding the provisions of subsection B of § 56-234 and §§ 56-249.6 and 56-585.1, upon application of a utility consumer services cooperative the Commission shall review a proposal submitted by the cooperative for a voluntary companion rate schedule. If the Commission finds that the proposal is reasonable and prudent, it shall approve the voluntary companion rate schedule for the cooperative to conduct a pilot program pursuant to this section. No utility consumer services cooperative shall be required to conduct a pilot program pursuant to this section. In making an application to the Commission pursuant to this subsection, a utility consumer services cooperative shall have flexibility to design its voluntary companion rate schedule in a manner that, notwithstanding anything to the contrary in this section, provides the cooperative the ability to:
1. Construct or purchase its generating facilities, or dedicate a portion of its existing power supply portfolio, for its community solar pilot program along with one or more other utility consumer services cooperatives, one or both Phase I or Phase II Utilities, or a utility aggregation cooperative, through requests for proposal or through a contract with a third party or a utility aggregation cooperative;
2. If constructing or purchasing its generating facilities, or dedicating a portion of its existing power supply portfolio, for its pilot program through a utility aggregation cooperative, include generating facilities that may be already in service or may be first placed into service at any time;
3. Utilize generating facilities of any generating capacity for its pilot program;
4. Physically locate the generating facilities used for the pilot program inside or outside of its certificated service territory;
5. Design its voluntary companion rate schedule in coordination with one or more utility consumer services cooperatives, such that participating subscribers from both cooperatives subscribe to an identical rate schedule;
6. Permanently end its pilot program for all subscribers according to the terms of the voluntary companion rate schedule; and
7. Recover pilot program costs that are not recovered through the voluntary companion rate schedule by including unrecovered purchased power expense in the cooperative's cost of purchased power and through a regulatory asset for unrecovered costs that are not purchased power expense, subject to the oversight of the cooperative's board of directors, which regulatory asset shall be approved by the Commission.
D. The participation of retail customers in a pilot program administered by a participating utility in the Commonwealth is in the public interest. Voluntary companion rate schedules approved by the Commission pursuant to this section are necessary in order to acquire information which is in furtherance of the public interest. The Commission shall approve the recovery of pilot program costs that it deems to be reasonable and prudent. The Commission shall also approve the pilot program design, the voluntary companion rate schedule, and the portfolio of participating generating facilities. No Commission review or approval of individual participating generating facilities, agreements, sites, or RFPs shall be required pursuant to this section or any other section of the Code.
E. Any voluntary companion rate schedule approved by the Commission pursuant to this section shall not be considered a tariff for electric energy provided 100 percent from renewable energy pursuant to § 56-577.
F. Each participating utility shall report on the status of its pilot program, including the number of subscribing customers, to the Governor, the Commission, and the Chairmen of the House Committee on Labor and Commerce and the Senate Committee on Commerce and Labor. The report shall be filed the earlier of (i) three years after the date a customer of the participating utility first subscribes to its pilot program or (ii) July 1, 2022. If a participating utility closes its pilot program to new subscribers pursuant to subdivision B 14, it shall notify the Governor, the Commission, and the Chairmen of the House Committee on Labor and Commerce and the Senate Committee on Commerce and Labor not later than three months after such closure, which notification shall (a) describe the reasons for the closure and (b) be provided in lieu of the status report otherwise required by this subsection.
G. At any time after filing its report on the status of its pilot program as required by subsection F, a participating utility may, in its application proceeding, move the Commission to make its pilot program permanent. The motion shall include a compliance filing with conforming changes to the participating utility's applicable rate schedules. Upon the Commission's granting of the motion, the pilot program shall become a regular rate schedule of the participating utility.
A. Prior to January 1, 2024, (i) the construction or purchase by a public utility of one or more solar or wind generation facilities located in the Commonwealth or off the Commonwealth's Atlantic shoreline, each having a rated capacity of at least one megawatt and having in the aggregate a rated capacity that does not exceed 5,000 megawatts, or (ii) the purchase by a public utility of energy, capacity, and environmental attributes from solar facilities described in clause (i) owned by persons other than a public utility is in the public interest, and the Commission shall so find if required to make a finding regarding whether such construction or purchase is in the public interest.
B. Prior to January 1, 2024, (i) the construction or purchase by a public utility of one or more solar or wind generation facilities located in the Commonwealth or off the Commonwealth's Atlantic shoreline, each having a rated capacity of less than one megawatt, including rooftop solar installations with a capacity of not less than 50 kilowatts, and having in the aggregate a rated capacity that does not exceed 500 megawatts, or (ii) the purchase by a public utility of energy, capacity, and environmental attributes from solar facilities described in clause (i) owned by persons other than a public utility is in the public interest, and the Commission shall so find if required to make a finding regarding whether such construction or purchase is in the public interest.
C. The aggregate cap of 5,000 megawatts of rated capacity described in clause (i) of subsection A, the aggregate cap of 500 megawatts of rated capacity described in clause (i) of subsection B, and the aggregate cap of 200 megawatts of rated capacity described in subsection I are separate and independent from each other. The capacity of facilities in subsection B shall not be counted in determining the capacity of facilities in subsection A or I; the capacity of facilities in subsection A shall not be counted in determining the capacity of facilities in subsection B or I; and the capacity of facilities in subsection I shall not be counted in determining the capacity of facilities in subsection A or B.
D. Twenty-five percent of the solar generation capacity placed in service on or after July 1, 2018, located in the Commonwealth, and found to be in the public interest pursuant to subsection A or B shall be from the purchase by a public utility of energy, capacity, and environmental attributes from solar facilities owned by persons other than a public utility. The remainder shall be construction or purchase by a public utility of one or more solar generation facilities located in the Commonwealth. All of the solar generation capacity located in the Commonwealth and found to be in the public interest pursuant to subsection A or B shall be subject to competitive procurement, provided that a public utility may select solar generation capacity without regard to whether such selection satisfies price criteria if the selection of the solar generating capacity materially advances non-price criteria, including favoring geographic distribution of generating capacity, areas of higher employment, or regional economic development, if such non-price solar generating capacity selected does not exceed 25 percent of the utility's solar generating capacity.
E. Construction, purchasing, or leasing activities for a test or demonstration project for a new utility-owned and utility-operated generating facility or facilities utilizing energy derived from offshore wind with an aggregate capacity of not more than 16 megawatts are in the public interest.
F. Prior to January 1, 2035, (i) the construction by a public utility of one or more energy storage facilities located in the Commonwealth, having in the aggregate a rated capacity that does not exceed 2,700 megawatts, or (ii) the purchase by a public utility of energy storage facilities described in clause (i) owned by persons other than a public utility or the capacity from such facilities is in the public interest, and the Commission shall so find if required to make a finding regarding whether such construction or purchase is in the public interest.
G. At least 35 percent of the energy storage capacity placed in service on or after July 1, 2020, located in the Commonwealth and found to be in the public interest pursuant to subsection F shall be from the purchase by a public utility of energy storage facilities owned by persons other than a public utility or the capacity from such facilities. All of the energy storage facilities located in the Commonwealth and found to be in the public interest pursuant to subsection F shall be subject to competitive procurement, provided that a public utility may select energy storage facilities without regard to whether such selection satisfies price criteria if the selection of the energy storage facilities materially advances non-price criteria, including favoring geographic distribution of generating facilities, areas of higher employment, or regional economic development, if such energy storage facilities selected for the advancement of non-price criteria do not exceed 25 percent of the utility's energy storage capacity.
H. A utility may elect to petition the Commission, outside of a triennial or biennial review proceeding conducted pursuant to § 56-585.1, at any time for a prudency determination with respect to the construction or purchase by the utility of one or more solar or wind generation facilities located in the Commonwealth or off the Commonwealth's Atlantic Shoreline or the purchase by the utility of energy, capacity, and environmental attributes from solar or wind facilities owned by persons other than the utility. The Commission's final order regarding any such petition shall be entered by the Commission not more than three months after the date of the filing of such petition.
I. Prior to January 1, 2024, (i) the construction or purchase by a public utility of one or more solar or wind generation facilities located on a previously developed project site in the Commonwealth having in the aggregate a rated capacity that does not exceed 200 megawatts or (ii) the purchase by a public utility of energy, capacity, and environmental attributes from solar facilities described in clause (i) owned by persons other than a public utility, is in the public interest.
2018, c. 296; 2020, cc. 1190, 1193, 1194, 1225; 2023, cc. 757, 775.
A. There is hereby established a pilot program to further the understanding of underground electric transmission lines in regard to electric reliability, construction methods and related cost and timeline estimating, the probability of meeting such projections, and the benefits of undergrounding existing electric transmission lines to promote economic development within the Commonwealth. The pilot program shall consist of the approval to construct qualifying electrical transmission lines of 230 kilovolts or less (but greater than 69 kilovolts) in whole or in part underground. Such pilot program shall consist of a total of two qualifying electrical transmission line projects, constructed in whole or in part underground, as specified and set forth in this section.
B. Notwithstanding any other law to the contrary, as a part of the pilot program established pursuant to this section, the Commission shall approve as a qualifying project a transmission line of 230 kilovolts or less that is pending final approval of a certificate of public convenience and necessity from the Commission as of December 31, 2017, for the construction of an electrical transmission line approximately 5.3 miles in length utilizing both overhead and underground transmission facilities, of which the underground portion shall be approximately 3.1 miles in length, which has been previously proposed for construction within or immediately adjacent to the right-of-way of an interstate highway. Once the Commission has affirmed the project need through an order, the project shall be constructed in part underground, and the underground portion shall consist of a double circuit.
The Commission shall approve such underground construction within 30 days of receipt of the written request of the public utility to participate in the pilot program pursuant to this section. The Commission shall not require the submission of additional technical and cost analyses as a condition of its approval but may request such analyses for its review. The Commission shall approve the underground construction of one contiguous segment of the transmission line that is approximately 3.1 miles in length that was previously proposed for construction within or immediately adjacent to the right-of-way of the interstate highway, for which, by resolution, the locality has indicated general community support. The remainder of the construction for the transmission line shall be aboveground. The Commission shall not be required to perform any further analysis as to the impacts of this route, including environmental impacts or impacts upon historical resources.
The electric utility may proceed to acquire right-of-way and take such other actions as it deems appropriate in furtherance of the construction of the approved transmission line, including acquiring the cables necessary for the underground installation.
C. In reviewing applications submitted by public utilities for certificates of public convenience and necessity for the construction of electrical transmission lines of 230 kilovolts or less filed between July 1, 2018, and October 1, 2020, the Commission shall approve, consistent with the requirements of subsection D, one additional application as a qualifying project to be constructed in whole or in part underground, as a part of this pilot program. The one qualifying project shall be in addition to the qualifying project described in subsection B and shall be the relocation or conversion of an existing 230-kilovolt overhead line to an underground line.
D. For purposes of subsection C, a project shall be qualified to be placed underground, in whole or in part, if it meets all of the following criteria: (i) an engineering analysis demonstrates that it is technically feasible to place the proposed line, in whole or in part, underground; (ii) the governing body of each locality in which a portion of the proposed line will be placed underground indicates, by resolution, general community support for the project and that it supports the transmission line to be placed underground; (iii) a project has been filed with the Commission or is pending issuance of a certificate of public convenience and necessity by October 1, 2020; (iv) the estimated additional cost of placing the proposed line, in whole or in part, underground does not exceed $40 million or, if greater than $40 million, the cost does not exceed 2.5 times the cost of placing the same line overhead, assuming accepted industry standards for undergrounding to ensure safety and reliability; if the public utility, the affected localities, and the Commission agree, a proposed underground line whose cost exceeds 2.5 times the cost of placing the line overhead may also be accepted into the pilot program; (v) the public utility requests that the project be considered as a qualifying project under this section; and (vi) the primary need of the project shall be for purposes of grid reliability, grid resiliency, or to support economic development priorities of the Commonwealth, including the economic development priorities and the comprehensive plan of the governing body of the locality in which at least a portion of line will be placed, and shall not be to address aging assets that would have otherwise been replaced in due course.
E. A transmission line project that is found to meet the criteria of subsection D shall be deemed to satisfy the requirements of subsection B of § 56-46.1 with respect to a finding of the Commission that the line is needed.
F. Approval of a transmission line pursuant to this section for inclusion in the pilot program shall be deemed to satisfy the requirements of § 15.2-2232 and local zoning ordinances with respect to such transmission line and any associated facilities, such as stations, substations, transition stations and locations, and switchyards or stations, that may be required.
G. The Commission shall report annually to the Commission on Electric Utility Restructuring, the Joint Commission on Technology and Science, and the Governor on the progress of the pilot program by no later than December 1 of each year that this section is in effect. The Commission shall submit a final report to the Commission on Electric Utility Restructuring, the Joint Commission on Technology and Science, and the Governor no later than December 1, 2024, analyzing the entire program and making recommendations about the continued placement of transmission lines underground in the Commonwealth. The Commission's final report shall include analysis and findings of the costs of underground construction and historical and future consumer rate effects of such costs, effect of underground transmission lines on grid reliability, operability (including operating voltage), probability of meeting cost and construction timeline estimates of such underground transmission lines, and economic development, aesthetic or other benefits attendant to the placement of transmission lines underground.
H. For the qualifying projects chosen pursuant to this section and not fully recoverable as charges for new transmission facilities pursuant to subdivision A 4 of § 56-585.1, the Commission shall approve a rate adjustment clause. The rate adjustment clause shall provide for the full and timely recovery of any portion of the cost of such project not recoverable under applicable rates, terms, and conditions approved by the Federal Energy Regulatory Commission and shall include the use of the fair return on common equity most recently approved in a State Corporation Commission proceeding for such utility. Such costs shall be entirely assigned to the utility's Virginia jurisdictional customers. The Commission's final order regarding any petition filed pursuant to this subsection shall be entered not more than three months after the filing of such petition.
I. The provisions of this section shall not be construed to limit the ability of the Commission to approve additional applications for placement of transmission lines underground. Approval by the Commission of a transmission line for inclusion in the program pursuant to subsection B shall preclude the placement of future overhead electrical transmission lines of at least 69 kilovolts in the same right-of-way as described in subsection B for a period of 10 years from July 1, 2018, but shall not preclude the placement of (i) any underground transmission lines in such right-of-way or (ii) any electrical distribution lines in such right-of-way.
J. If two applications are not submitted to the Commission that meet the requirements of this section, the Commission shall document the failure of the projects to qualify for the pilot program in order to justify approving fewer than two projects to be placed underground, in whole or in part.
K. Insofar as the provisions of this section are inconsistent with the provisions of any other law or local ordinance, the provisions of this section shall be controlling.
A. The Commission shall establish pilot programs under which each Phase I Utility and each Phase II Utility, as such terms are defined in subdivision A 1 of § 56-585.1, shall submit a proposal to deploy electric power storage batteries. A proposal shall provide for the deployment of batteries pursuant to a pilot program that accomplishes at least one of the following: (i) improve reliability of electrical transmission or distribution systems; (ii) improve integration of different types of renewable resources; (iii) deferred investment in generation, transmission, or distribution of electricity; (iv) reduced need for additional generation of electricity during times of peak demand; or (v) connection to the facilities of a customer receiving generation, transmission, and distribution service from the utility. A Phase I Utility may install batteries with up to 10 megawatts of capacity. A Phase II Utility may install batteries with up to 30 megawatts of capacity. Each pilot program shall have a duration of five years. The pilot program shall provide for the recovery of all reasonable and prudent costs incurred under the pilot program through the electric utility's base rates on a nondiscriminatory basis. Any pilot program proposed by a Phase I Utility or Phase II Utility that satisfies the requirements of this subsection is in the public interest.
B. The Commission shall, by December 1, 2018, adopt such rules or establish such guidelines as may be necessary for the general administration of pilot programs to deploy electric power storage batteries established by subsection A.
2018, c. 296.
A. The Commission shall require a Phase II Utility as defined in subdivision A 1 of § 56-585.1 to submit a proposal to the Commission to conduct a pilot program, not to exceed 10 megawatts in the aggregate, in its certificated service territory to allow any school in a public school division in the Commonwealth that generates electricity from a wind-powered or solar-powered renewable energy generation facility located at the school in amounts that exceed the amount of electricity consumed by the school in a billing period, at the option of the school board, to either (i) credit such excess electricity to the metered accounts of one or more other schools in the same public school division, as directed by the school board, in a manner that reduces the amount of electricity for which the other school or schools are billed and provides the other school or schools with a credit against the amount billed to the other school or schools, which credit shall be at the same rate that the school or schools would otherwise be charged for such amount of electricity, without the assessment by the supplier of any service charges or fees in connection with or arising out of such crediting or (ii) receive payment for such excess electricity from the electric utility at the contractually negotiated rate. The duration of any pilot program approved by the Commission pursuant to this section shall be six years.
B. The Commission shall, by December 1, 2018, adopt such rules or establish such guidelines as may be necessary for its general administration of the pilot program established under this section.
C. Any electric utility participating in the pilot program established under this section shall report to the General Assembly by December 1 of each year the pilot program is in effect, commencing in 2020, regarding the status of the pilot program's enrollment and any other information that may be appropriate.
2018, c. 415.
A. As used in this section:
"Host account" means the premises on which a municipal customer-generator's electrical generating facility is located.
"Municipal customer-generator" means a municipality that owns or operates, or that contracts with other persons to own or operate, an electrical generating facility that (i) uses as its total source of fuel renewable energy as defined in § 56-576, (ii) has a generating capacity of not more than three megawatts, (iii) is located on land owned or leased by the municipality within the municipality and is connected to the municipality's wiring on the municipality's side of its interconnection with the utility, (iv) is interconnected and operated in parallel with the utility's transmission and distribution facilities, and (v) is intended primarily to offset all or part of the municipal customer-generator's own electricity requirements. The capacity of any generating facility installed under this section, other than a generating facility located on airports, landfills, parking lots and garages, wastewater treatment sites, parks, post-mine land, or a reservoir that is owned, operated, or leased by the municipality, shall not exceed the same limitation established with respect to an eligible customer-generator as set forth in the definition of such term in subsection B of § 56-594.
"Municipality" means any county, city, or town in the Commonwealth, other than a municipality that owns and operates its own electric utility, or any authority created pursuant to the Park Authorities Act (§ 15.2-5700 et seq.).
"Net energy metering" means measuring the difference, over the net metering period, between (i) electricity supplied to a municipal customer-generator from the electric grid and (ii) the electricity generated and fed back to the electric grid by the municipal customer-generator.
"Net metering period" means the 12-month period following the date of final interconnection of the municipal customer-generator's system with its utility and each 12-month period thereafter.
"Phase I Utility" and "Phase II Utility" have the same meaning as defined in § 56-585.1:3.
"Utility" means a Phase I Utility or Phase II Utility.
B. The Commission shall require each Phase I Utility to submit a proposal to the Commission to conduct a pilot program for municipal net energy metering in accordance with the following terms, conditions, and restrictions:
1. A pilot program shall be conducted within the service territory of each Phase I Utility. The pilot program shall allow any municipal customer-generator that generates electricity from a renewable energy generation facility in amounts that exceed the amount of the utility's electricity consumed by the host municipal customer-generator account to credit one or more of the municipality's target metered accounts or metered accounts of the public school division of the municipality. In each Phase I Utility's pilot program, the target accounts may be at one or more other separately utility-metered public buildings or facilities at contiguous or noncontiguous sites owned by the municipality and used for a public purpose. In each Phase I Utility's pilot program, excess electricity beyond that used by the host account shall be credited to the metered account of the target municipal customer in the same municipality, such that the generation energy charges on the electric bills of such target's metered accounts shall be reduced by the amount of the excess generation kilowatt-hours apportioned to the metered accounts multiplied by the applicable generation energy rate of the target's accounts. The generation energy rate of the target's accounts includes all applicable kilowatt-hour-based rate adjustment clauses with the exception of any non-fuel-related or non-generation-related kilowatt-hour-based rate adjustment clauses. The netting of the amount of electricity generated and the amount of electricity consumed, and the crediting for the amount of any excess generation determined as a result of such netting, shall occur in the twelfth month following the commencement of the host municipal customer-generator's generation of electricity under a pilot program and annually thereafter, regardless of the municipal customer-generator's regular billing period.
2. The pilot program shall not limit the current authority of any municipality to participate in any other net energy metering program.
3. The amount of generating capacity of the generating facilities that are the subject of a pilot program under this subsection shall not exceed five megawatts, although the Phase I Utility may, in its discretion, increase the generating capacity that is part of the program up to 10 megawatts.
4. The aggregated capacity of all generation facilities that are the subject of each Phase I Utility's pilot program under this subsection shall constitute a portion of the existing limit of the utility's adjusted Virginia peak-load forecast of the previous year that is available to (i) municipal customer-generators under this section, (ii) eligible customer-generators and eligible agricultural customer-generators under § 56-594, and (iii) small agricultural generators under § 56-594.2 in the utility's service area. Municipal customer-generators shall be eligible to participate in a Phase I Utility's pilot program implemented under this subsection on a first-come, first-served basis in each utility's Virginia service area until the limits set forth in subdivision 3 are met.
C. The Commission shall require each Phase II Utility to submit a proposal to the Commission to conduct a pilot program for municipal net energy metering in accordance with the following terms, conditions, and restrictions:
1. A pilot program shall be conducted within the service territory of each Phase II Utility. The pilot program shall allow any municipal customer-generator that generates electricity from a renewable energy generation facility in amounts that exceed the amount of the utility's electricity consumed by the municipal customer-generator host account to credit one or more of the municipality's target metered accounts (target accounts or beneficial accounts). In each Phase II Utility's pilot program, the target accounts may be at one or more other separately utility-metered public buildings or facilities at contiguous or noncontiguous sites owned or leased by the municipality within the municipality. In each Phase II Utility's pilot program, excess electricity beyond that used by the host account shall be credited to the beneficial accounts selected by the municipal customer in the same municipality. The generation energy charges on the electric bills of such beneficial accounts shall be reduced by the amount of the excess electricity kilowatt-hours apportioned to the net metered accounts multiplied by the applicable generation rate of the selected beneficial accounts. The generation energy rate of each selected beneficial account shall include all applicable rate adjustment clauses and riders, including fuel riders, with the exception of any non-fuel-related or non-generation-related riders. Non-bypassable charges shall be excluded from reductions on beneficial accounts. The netting of the amount of electricity generated and the amount of electricity consumed, and the crediting for the amount of any excess electricity determined as a result of such netting, shall occur in the twelfth month following the commencement of the host municipal customer-generator's generation of electricity under a pilot program and annually thereafter, regardless of the municipal customer-generator's regular billing period.
2. The pilot program shall not limit the current authority of any municipality to participate in any other net energy metering program.
3. The amount of generating capacity of the generating facilities that are the subject of a pilot program under this subsection shall not exceed 25 megawatts.
4. Municipal customer-generators shall be eligible to participate in a Phase II Utility's pilot program implemented under this subsection on a first-come, first-served basis in each utility's Virginia service area until the limits set forth in subdivision 3 are met.
D. Any pilot program conducted under this section shall require that:
1. If conducted by a Phase I Utility or Phase II Utility, each participating municipality shall be responsible for all demonstrated administrative costs associated with implementing the pilot program, including demonstrated administrative costs associated with crediting excess electricity to target accounts; and
2. If conducted by a Phase I Utility, the credit for excess electricity, to the extent possible, shall be prioritized to be directed to accounts at buildings or facilities of the public school division of the municipality before the credit is directed to any of the municipality's target accounts.
Any pilot program conducted pursuant to this section shall not limit the current authority of any municipality to participate in any other net energy metering program.
Neither jurisdictional customers nor non-jurisdictional customers, including those that are members of a joint powers association representing member units of a political subdivision of the Commonwealth, that do not participate in a pilot program under this section shall bear any costs associated with participation in such pilot program by a participating host municipal customer-generator and participating target municipal customer.
E. The duration of any pilot program approved by the Commission pursuant to subsection B shall be six years. The duration of any pilot program approved by the Commission pursuant to subsection C shall be until July 1, 2028. If a pilot program is not extended beyond such initial term, host and target accounts participating at the end of the initial term shall be permitted to continue to participate under the terms of the pilot program that existed during the initial term. The terms of the pilot program shall be included in future contracts for each municipality that elects to continue its program.
F. The Commission shall review the pilot program established pursuant to subsection B in 2021 and every two years thereafter for the duration of the pilot program. The Commission shall review the pilot program established pursuant to subsection C in 2024 and every two years thereafter for the duration of the pilot program.
G. Notwithstanding the provisions of § 56-594.02, the aggregated capacity of all generation facilities that are the subject of a utility's pilot program pursuant to this section shall not constitute any portion of the existing aggregate net metering cap established in § 56-594 and evaluated by the Commission as part of a net energy metering proceeding.
H. The aggregated capacity of all generation facilities that are the subject of each utility's pilot program under this section and that are the subject of a third-party power purchase agreement shall constitute a portion of the existing limit of pilot programs pursuant to the provisions of § 56-594.02.
A. Each Phase I Utility and each Phase II Utility, as such terms are defined in subdivision A 1 of § 56-585.1, may submit one or more petitions to provide or make available broadband capacity to Internet service providers in areas of the Commonwealth unserved by broadband. The provision of such broadband capacity to Internet service providers in areas of the Commonwealth unserved by broadband pursuant to this section is in the public interest.
B. The costs of providing broadband capacity pursuant to any such petition, net of revenue generated therefrom, shall be eligible for recovery from customers as an electric grid transformation project pursuant to clause (vi) of subdivision A 6 of § 56-585.1 filed on or after July 1, 2021, as a non-bypassable charge. Notwithstanding any provision of subdivision A 6 or 7 of § 56-585.1, the utility may file one or more petitions for approval of such a rate adjustment clause, on a stand-alone basis, seeking recovery of the costs of providing broadband capacity at any time on or after July 1, 2021, and the Commission shall issue its final order regarding such petition within six months following the date of filing.
C. Notwithstanding the provisions of § 13.1-620 or the articles of incorporation of an investor-owned utility, an investor-owned utility may, either directly or through an affiliate or subsidiary, pursuant to a petition that the Commissioner approves pursuant to this section, (i) own, manage, or control any broadband capacity equipment and electronics, including any plant, works, system, lines, facilities, or properties, or any part or parts thereof, together with all appurtenances thereto, used or useful in connection with the provision and extension of such broadband services; (ii) lease indefeasible rights of use in such broadband capacity equipment and electronics to Internet service providers in areas of the Commonwealth unserved by broadband pursuant to this section; and (iii) provide access points that are outside the utility's energized zone to allow connection between the utility's broadband capacity system and the Internet service provider's system.
D. Each petition to provide broadband capacity pursuant to this section that an investor-owned utility submits to the Commission shall identify the Internet service provider to which the utility shall lease such capacity, together with the area to be served using such capacity. The Commission shall, after notice and opportunity for hearing, initiate proceedings to review each petition submitted. The Commission shall condition any approval of such petition on the requirement that construction shall commence within 18 months of such approval. If the utility fails to commence construction within such time period, the utility may resubmit the petition for conditional approval. The Commission shall also condition any approval of such petition on the requirement that the utility and its Internet service provider submit annual public reports on construction progress by the utility and delivery of broadband services by the Internet service provider until construction is completed. The Commission's final order regarding any such petition shall be entered by the Commission no more than six months after the date of filing of such petition. An area shall be determined to be unserved by broadband if (i) the Department of Housing and Community Development has certified within the last 18 months that the designated area is unserved; (ii) the Virginia Telecommunication Initiative of the Department of Housing and Community Development has issued a grant or loan to construct a broadband service project within the last 18 months, and the grant or loan recipient is the Internet service provider to which the utility proposes to lease capacity; (iii) the federal government has issued a grant or loan or has provided support to construct a broadband service project in the designated area within the last 18 months, and the grant or loan recipient is the Internet service provider to which the utility proposes to lease capacity; or (iv) the Commission determines the area is unserved on the basis of other competent evidence. The determination of the Department of Housing and Community Development that an area is unserved shall be made following public notice of the proposed finding and an opportunity for third parties to challenge such finding, and such determination shall be presumed sufficient for the Commission to find the area to be unserved. The Commission may determine that an area is unserved on the basis of other competent evidence.
E. An investor-owned utility shall be responsible for obtaining all necessary rights-of-way or other easements or real property rights to permit leasing of broadband capacity to Internet service providers. An Internet service provider shall be responsible for obtaining all necessary rights-of-way or other easements or real property rights from utility access point to permit the provision of broadband services to end-user customers.
F. As used in this section:
"Broadband" means Internet access at speeds equal to or greater than the adequate speed as determined by the broadband guidelines set out by the Department of Housing and Community Development for its Virginia Telecommunication Initiative from time to time.
"Unserved by broadband" means a designated area in which less than 10 percent of residential and commercial units are capable of receiving broadband service, provided that the Department of Housing and Community Development for its Virginia Telecommunication Initiative may by guideline increase such percentage from time to time.
G. No investor-owned utility nor any affiliate thereof may offer broadband or Internet service provider services to residential or commercial end-user customers in the Commonwealth pursuant to this section. Nothing in this section shall be construed to prevent an investor-owned utility or an affiliate thereof from providing transport of or capacity for broadband or Internet service in the Commonwealth as a wholesaler or intermediate vendor, provided that an unaffiliated third party is the provider of broadband or Internet services to the end-user customer.
H. The provision and extension of broadband capacity by an incumbent electric utility to an area of the Commonwealth unserved by broadband pursuant to a petition that the Commission approves pursuant to this section, including any business activity related to the construction or leasing of broadband capacity facilities, shall be exempt from any rules and regulations that the Commission has promulgated or may promulgate governing functional separation of generation, retail transmission, and distribution of incumbent electric utilities. Investor-owned electric utilities may for the purposes of this section engage in such coordination between and among their various corporate divisions as necessary for the purposes of providing broadband capacity to an area of the Commonwealth unserved by broadband.
I. Notwithstanding the provisions of § 13.1-620 or the articles of incorporation of an investor-owned utility, an investor-owned utility may, either directly or through an affiliate or subsidiary, lease broadband-related assets or capacity to any third party. The revenues generated from such leases shall offset (i) the costs of the petition recovered through the rate adjustment clause described in subsection B or (ii) the utility's electric cost of service.
2019, c. 619; 2020, c. 752; 2021, Sp. Sess. I, cc. 356, 357, 369, 370.
The Virginia Economic Development Partnership shall conduct a program with each Phase I and Phase II Utility, as those terms are defined in subsection A of § 56-585, in each such utility's service territory or transmission zone for the purpose of promoting economic development in areas of the Commonwealth. The program shall allow any such utility to complete the construction phase of a transmission line and any associated substation and other associated facilities to provide electric transmission and distribution infrastructure to a business park, as defined in § 56-576, located within the utility's transmission zone where investments by a locality or 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 the siting, environmental review, pre-engineering design, and transmission right-of-way acquisition have been made prior to the public announcement of a prospective occupant of the business park. Each program shall be subject to the following terms, conditions, and restrictions:
1. The costs incurred by a Phase I or Phase II Utility after January 1, 2019, to construct, operate, and maintain the business park electric infrastructure in order to provide service to a business park participating in the program outlined by this section shall be recovered by the utility pursuant to a rate adjustment clause approved by the Commission in subdivision A 4 of § 56-585.1.
2. Each individual qualifying project shall be less than 10 miles in length.
3. The role of the Virginia Economic Development Partnership in conducting the program outlined by this section is to certify that up to two petitions per year for each Phase I and Phase II utility address the eligibility criteria for participation in the program set forth in § 56-576 and in this section.
4. For construction of business park electric infrastructure, a utility shall either (i) obtain a certificate from the Commission pursuant to subdivision A 1 of § 56-265.2, unless such infrastructure is an ordinary extension or improvement in the usual course of business or (ii) obtain approval pursuant to the requirements of § 15.2-2232 and any applicable zoning ordinances by the locality or localities in which the business park electric infrastructure will be located. If the utility seeks a certificate pursuant to subdivision A 1 of § 56-265.2, the Commission shall issue its decision on the expedited certificate application no later than six months from the date of filing. The need for any business park electric infrastructure shall be satisfied if the business park to be served is approved for the program by the Virginia Economic Development Partnership.
A. As used in this section:
"Advanced clean energy buyer" means a commercial or industrial customer of a Phase II Utility, irrespective of generation supplier, (i) with an aggregate load over 100 megawatts; (ii) with an aggregate amount of at least 200 megawatts of solar or wind energy supply under contract with a term of 10 years or more from facilities located within the Commonwealth by January 1, 2024; and (iii) that directly procures from the utility the electric supply and environmental attributes of the offshore wind facility associated with the lesser of 50 megawatts of nameplate capacity or 15 percent of the commercial or industrial customer's annual peak demand for a contract period of 15 years.
"Aggregate load" means the combined electrical load associated with selected accounts of an advanced 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" means the legal right, directly or indirectly, to direct or cause the direction of the management, actions, or policies of an affiliated entity, whether through the ability to exercise voting power, by contract, or otherwise. "Control" does not include control of an entity through a franchise or similar contractual agreement.
"Offshore wind affiliate" means a regulated affiliate company of a Phase II Utility subject to the Commission's jurisdiction established by such utility in connection with any project constructed pursuant to subdivision C 1 for the purpose of securing a noncontrolling equity financing partner for the project.
"Qualifying large general service customer" means a customer of a Phase II Utility, irrespective of general supplier, (i) whose peak demand during the most recent calendar year exceeded five megawatts and (ii) that contracts with the utility to directly procure electric supply and environmental attributes associated with the offshore wind facility in amounts commensurate with the customer's electric usage for a contract period of 15 years or more.
"Wind turbine generator" means a structure composed of a tower, a rotor with blades connected at the hub, and nacelle and ancillary electrical and other equipment that is affixed to a foundation of which multiple structures comprise a generating facility.
B. In order to meet the Commonwealth's clean energy goals, prior to December 31, 2032, the construction or purchase by a public utility of 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, is in the public interest and the Commission shall so find, provided that no customers of the utility shall be responsible for costs of any such facility in a proportion greater than the utility's ownership share of the facility, including any ownership share held by an offshore wind affiliate.
C. 1. Pursuant to subsection B, construction by a Phase II Utility of one or more new utility-owned and utility-operated generating facilities utilizing energy derived from offshore wind and located off the Commonwealth's Atlantic shoreline, with an aggregate rated capacity of not less than 2,500 megawatts and not more than 3,000 megawatts, along with electrical transmission or distribution facilities associated therewith for interconnection is in the public interest. In acting upon any request for cost recovery by a Phase II Utility or its offshore wind affiliate for costs associated with such a facility, the Commission shall determine the reasonableness and prudence of any such costs, provided that such costs shall be presumed to be reasonably and prudently incurred if the Commission determines that (i) the utility has complied with the competitive solicitation and procurement requirements pursuant to subsection E; (ii) the project's projected total levelized cost of energy, including any tax credit, on a cost per megawatt hour basis, inclusive of the costs of transmission and distribution facilities associated with the facility's interconnection, does not exceed 1.4 times the comparable cost, on an unweighted average basis, of a conventional simple cycle combustion turbine generating facility as estimated by the U.S. Energy Information Administration in its Annual Energy Outlook 2019; and (iii) the utility has commenced construction of such facilities for U.S. income taxation purposes prior to January 1, 2024, or has a plan for such facility or facilities to be in service prior to January 1, 2028. The Commission shall disallow costs, or any portion thereof, only if they are otherwise unreasonably and imprudently incurred. In its review, the Commission shall give due consideration to (a) the Commonwealth's renewable portfolio standards and carbon reduction requirements, (b) the promotion of new renewable generation resources, and (c) the economic development benefits of the project for the Commonwealth, including capital investments and job creation, arising from project construction and operation and the manufacture of wind turbine generator components and subcomponents.
2. Notwithstanding the provisions of § 56-585.1, the Commission shall not grant an enhanced rate of return to a Phase II Utility for the construction of one or more new utility-owned and utility-operated generating facilities utilizing energy derived from offshore wind and located off the Commonwealth's Atlantic shoreline pursuant to this section.
3. Any such costs proposed for recovery through a rate adjustment clause pursuant to subdivision A 6 of § 56-585.1 shall be allocated to all customers of the utility in the Commonwealth as a non-bypassable charge, regardless of the generation supplier of any such customer, other than (i) PIPP eligible utility customers, (ii) advanced clean energy buyers, and (iii) qualifying large general service customers. No electric cooperative customer of the utility shall be assigned, nor shall the utility collect from any such cooperative, any of the costs of such facilities, including electrical transmission or distribution facilities associated therewith for interconnection. The Commission may promulgate such rules, regulations, or other directives necessary to administer the eligibility for these exemptions.
4. The Commission shall permit a portion of the nameplate capacity of any such facility, in the aggregate, to be allocated to (i) advanced clean energy buyers or (ii) qualifying large general service customers, provided that no more than 10 percent of the offshore wind facility's capacity is allocated to qualifying large general service customers. A Phase II Utility or its offshore wind affiliate shall petition the Commission for approval of a special contract with any advanced clean energy buyer, or any special rate applicable to qualifying large general service customers, pursuant to § 56-235.2, no later than 15 months prior to the projected commercial operation date of the facility, and all customer enrollments associated with such special contracts or rates shall be completed prior to commercial operation of the facility. Any such special contract or rate may include provisions for levelized rates of service over the duration of the customer's contracted agreement with the utility, and the Commission shall determine that such special contract or rate is designed to hold nonparticipating customers harmless over its term in connection with any petition for approval by the utility. The utility may petition for approval of such special contracts or rates in connection with any petition for approval of a rate adjustment clause pursuant to subdivision A 6 of § 56-585.1 to recover the costs of the facility, and the Commission shall rule upon any such petitions in its final order in such proceeding within nine months from the date of filing.
D. In constructing any such facility contemplated in subsection B, the utility shall develop and submit a plan to the Commission for review that includes the following considerations: (i) options for utilizing local workers; (ii) the economic development benefits of the project for the Commonwealth, including capital investments and job creation; (iii) consultation with the Commonwealth's Chief Workforce Development Officer, the Chief Diversity, Equity, and Inclusion Officer, and the Virginia Economic Development Partnership on opportunities to advance the Commonwealth's workforce and economic development goals, including furtherance of apprenticeship and other workforce training programs; (iv) giving priority to the hiring, apprenticeship, and training of veterans, as that term is defined in § 2.2-2000.1, local workers, and workers from historically economically disadvantaged communities; and (v) procurement of equipment from Virginia-based or United States-based manufacturers using materials or product components made in Virginia or the United States, if reasonably available and competitively priced.
E. Any project constructed or purchased pursuant to subsection B shall (i) be subject to competitive procurement or solicitation for a substantial majority of the services and equipment, exclusive of interconnection costs, associated with the facility's construction; (ii) involve at least one experienced developer; and (iii) demonstrate the economic development benefits within the Commonwealth, including capital investments and job creation. A utility may give appropriate consideration to suppliers and developers that have demonstrated successful experience in offshore wind.
F. Any project constructed or purchased pursuant to subsection B shall include an environmental and fisheries mitigation plan submitted to the Commission for the construction and operation of such offshore wind facilities, provided that such plan includes an explicit description of the best management practices the bidder will employ that considers the latest science at the time the proposal is made to mitigate adverse impacts to wildlife, natural resources, ecosystems, and traditional or existing water-dependent uses. The plan shall include a summary of pre-construction assessment activities, consistent with federal requirements, to determine the spatial and temporal presence and abundance of marine mammals, sea turtles, birds, and bats in the offshore wind lease area.
G. In connection with any project constructed by a Phase II Utility pursuant to subdivision C 1, such utility may, subject to Commission approval pursuant to Chapter 4 (§ 56-76 et seq.), establish an offshore wind affiliate for the purpose of securing a noncontrolling equity financing partner for the project, and such offshore wind affiliate may be permitted to construct, own, or operate such project pursuant to subdivision C 1, or a portion thereof. Notwithstanding the provisions of the Utility Facilities Act (§ 56-265.1 et seq.), an offshore wind affiliate shall be permitted to operate as a public utility in association with the Phase II Utility and shall be entitled to all rights and privileges of a public utility solely in connection with the project. Nothing in this subsection shall prevent the Phase II Utility or its offshore wind affiliate from recovering the prudently incurred costs of constructing or operating the project pursuant to this section or subdivision A 6 of § 56-585.1, regardless of whether such costs are incurred by the utility or its offshore wind affiliate. In acting upon any such request for cost recovery by the Phase II Utility, the Commission shall utilize the capital structure and cost of capital of the utility, consistent with subdivision A 10 of § 56-585.1, and the capital structure and cost of capital of any noncontrolling entity's interest in the offshore wind affiliate shall be disregarded. If any ownership interest in the offshore wind affiliate is transferred to such a noncontrolling entity, the Commission shall ensure, in granting any approval for such transfer pursuant to the Utility Transfers Act (§ 56-88 et seq.), or for cost recovery under this section or subdivision A 6 of § 56-585.1, that any gain on the utility's basis for the project is credited to the utility's customers through a rate adjustment clause credit mechanism and amortized over such period as the Commission determines to be appropriate.
2020, cc. 1193, 1194, 1240, 1273, 1279; 2021, Sp. Sess. I, c. 328; 2023, cc. 510, 808, 809.
A. As used in this section:
"Applicable bill credit rate" means the dollar-per-kilowatt-hour rate as defined in subsection D used to calculate a subscriber's bill credit. The applicable bill credit rate shall be set such that the shared solar program results in robust project development and shared solar program access for all customer classes.
"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.
"Investor-owned utility" means each investor-owned utility in the Commonwealth including, notwithstanding subsection G of § 56-580, any investor-owned utility whose service territory assigned to it by the Commission is located entirely within the Counties of Dickenson, Lee, Russell, Scott and Wise. "Investor-owned utility" does not include a Phase I Utility, as that term is defined in subdivision A 1 of § 56-585.1.
"Multi-family shared solar program" or "program" means the program created through the adoption of rules to allow for the development of shared solar facilities described in subsection C.
"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 3,000 kW alternating current at any single location or that does not exceed 5,000 kW alternating current at contiguous locations owned by the same entity or affiliated entities;
2. Is operated pursuant to a program whereby at least three subscribers receive a bill credit for the electricity generated from the facility in proportion to the size of their subscription;
3. Is located in the service territory of an investor-owned utility;
4. Is connected to the electric distribution grid serving the Commonwealth; and
5. Is located on a parcel of land on the premises of the multi-family utility customer or adjacent thereto.
"Subscriber" means a multi-family customer of an investor-owned electric utility that owns one or more subscriptions of a shared solar facility that is interconnected with the utility.
"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.
"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.
B. The Commission shall establish by regulation a program that affords eligible multi-family customers of investor-owned utilities the opportunity to participate in shared solar projects. The regulations shall be adopted by the Commission by January 1, 2021.
C. An investor-owned utility shall provide a bill credit to a subscriber's subsequent monthly electric bill 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 shall be carried over and applied to the next month's bill in perpetuity;
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, provide to the investor-owned utility a subscriber list indicating the kilowatt-hours of generation attributable to each of the retail customers participating in a shared solar facility in accordance with the subscriber's portion of the output of the shared solar facility;
4. Lists may be updated monthly to reflect canceling subscribers and to add new subscribers. The investor-owned utility shall apply bill credits to subscriber bills within one billing cycle following the cycle during which the energy was generated by the shared solar facility;
5. The investor-owned 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. On an annual basis, the subscriber organization shall furnish to the utility allocation instructions for distributing excess bill credits to subscribers; and
7. All environmental attributes associated with a shared solar facility, including renewable energy certificates, shall be considered property of the subscriber organization. At the subscriber organization's discretion, those attributes may be distributed to subscribers, sold to investor-owned utilities or other buyers, accumulated, or retired.
D. The Commission shall annually calculate the applicable bill credit rate as the effective retail rate of the customer's rate class, which shall be inclusive of all supply charges, delivery charges, demand charges, fixed charges, and any applicable riders or other charges to the customer. This rate shall be expressed in dollars or cents per kilowatt-hour.
E. The Commission shall establish by regulation a multi-family shared solar program by January 1, 2021, and shall require each investor-owned utility to file any tariffs, agreements, or forms necessary for implementation of the program. Any rule or utility implementation filings approved by the Commission shall:
1. Reasonably allow for the creation and financing of shared solar facilities;
2. Allow all customer classes to participate in the program, and ensure participation opportunities for all customer classes;
3. Not remove a customer from its otherwise applicable customer class in order to participate in a shared solar facility;
4. Reasonably allow for the transferability and portability of subscriptions, including allowing a subscriber to retain a subscription in a shared solar facility if the subscriber moves within the same utility territory;
5. Establish uniform 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;
6. Adopt standardized consumer disclosure forms;
7. Allow the investor-owned utilities to recover reasonable costs of administering the program;
8. Ensure nondiscriminatory and efficient requirements and utility procedures for interconnecting projects;
9. Address the colocation of two or more shared solar facilities on a single parcel of land, and provide guidelines for determining when two or more facilities are colocated; and
10. Include a program implementation schedule.
F. Within 180 days of finalization of the Commission's adoption of regulations for the shared solar program, utilities shall begin crediting subscriber accounts of each shared solar facility interconnected in its service territory.
Beginning July 1, 2021, any approved costs of any investor-owned electric utility associated with investment in transportation electrification, other than those costs approved prior to July 1, 2021, shall be recovered only through the utility's rates for generation and distribution, shall not be recovered through a rate adjustment clause pursuant to subdivision A 6 of § 56-585.1, and shall not be eligible for a customer credit reinvestment offset pursuant to subdivision A 8 d of § 56-585.1. To the extent that the provisions of this section are inconsistent with the provisions of § 56-585.1, the provisions of this section shall control.
2021, Sp. Sess. I, c. 268.
A. As used in this section:
"Small modular reactor" or "SMR" means a nuclear reactor that produces nuclear power and has a nameplate capacity that does not exceed 500 megawatts of generating capacity per reactor.
"SMR facility" means an SMR or multiple SMRs that generate electricity at a single site.
"SMR project development costs" or "project costs" means all costs associated with the development of one or more SMRs, including costs of evaluation, design, engineering, federal approvals and licensing, environmental analysis and permitting, early site permitting, equipment procurement, and authorized rate of return.
"Utility" means a Phase II Utility, as that term is defined in subdivision A 1 of § 56-585.1.
B. Notwithstanding any limitation under subdivision A 6 of § 56-585.1, the utility may petition the Commission at any time for approval of a rate adjustment clause pursuant to subdivision A 6 of § 56-585.1 for the recovery of SMR project development costs. The utility may petition the Commission for up to one SMR facility pursuant to this section. Such utilities may petition the Commission for SMR project development cost recovery along separate development phases and, if the Commission determines such projected or actual project costs to be reasonable and prudent, such project costs may be recovered by such utility on a timely and current basis from customers prior to any approval pursuant to subsection D of § 56-580 or the commercial operation date of any such SMR facility. Any SMR project development costs incurred prior to July 1, 2024, and 20 percent of SMR project development costs incurred after July 1, 2024, shall not be eligible for accelerated cost recovery pursuant to this section and may be recovered through the utility's rates for generation and distribution services pursuant to subdivision A 1 of § 56-585.1. The utility that petitions the Commission for recovery of SMR project development costs shall demonstrate that such utility has evaluated funding opportunities from the U.S. Department of Energy. Nothing in this section shall limit the Commission's discretion to determine whether the proposed SMR project development costs are reasonable and prudent. As part of a final order approving such cost recovery, the Commission may impose a deadline by which the relevant utility shall either (i) place an SMR into commercial operation or (ii) sell the permitted site, unless it is at a previously existing nuclear site, and return the proceeds of the sale to customers. The length of such deadline shall be at the Commission's discretion; however, it shall provide the utility a reasonable timeframe in which to obtain all necessary permits and approvals, including allowing for approval by federal agencies such as the Nuclear Regulatory Commission, and completing construction of an SMR.
C. Nothing in this section shall limit the Commission's authority to approve or deny a petition for recovery of SMR project development costs or to require a utility to demonstrate that such utility made reasonable good-faith efforts to secure appropriate funding opportunities from the U.S. Department of Energy. The annual revenue requirement for any rate adjustment clause authorized pursuant to this section shall not exceed an amount that would increase the monthly bill of the utility's typical Virginia residential customer, utilizing 1,000 kilowatt hours of electricity monthly, by more than $1.40.
2024, c. 789.
A. As used in this section:
"Phase I Utility" means an investor-owned incumbent electric utility that was, as of July 1, 1999, not bound by a rate case settlement adopted by the Commission that extended its application beyond January 1, 2002.
"Project development costs" means all capital and operation and maintenance costs associated with a potential small modular nuclear facility incurred by a Phase I Utility before issuance of a certificate for a small modular nuclear facility located in the Commonwealth, including the costs of evaluation, design, engineering, environmental analysis and permitting, land options or acquisition, and early site permitting, as that term is defined in 10 C.F.R. § 52.1. "Project development costs" does not include the costs to obtain construction permits, combined licensing costs required by the Nuclear Regulatory Commission, or construction costs other than construction costs necessary for early site permitting.
"Small modular nuclear facility" means a nuclear reactor that has a rated electric generating capacity of not more than 500 megawatts that is capable of being constructed and operated either alone or in combination with one or more similar reactors at a single site.
B. Prior to the filing of an application for a certificate to construct a small modular nuclear facility to serve customers in the Commonwealth or in West Virginia and no earlier than July 1, 2024, a Phase I Utility may request the Commission to review the Phase I Utility's decision to incur project development costs. The Commission shall hold a hearing regarding the request and shall issue a final order within 180 days after the date on which the Phase I Utility files its request.
C. All approved reasonable and prudent project development costs incurred for a potential small modular nuclear facility shall be recovered through a rate adjustment clause filed pursuant to subdivision A 6 of § 56-585.1, amortized over a period equal to the period during which the costs were incurred or five years, whichever is greater. Beginning July 1, 2025, a Phase I Utility may make annual filings pursuant to subdivision A 6 of § 56-585.1 to recover project development costs incurred for a small modular nuclear facility, provided that the annual revenue requirement shall not exceed $25 million and that the overall project development costs recovered in such rate adjustment clause shall not exceed $125 million, excluding the cost of acquiring a site. Any such rate adjustment clause shall not be implemented prior to January 1, 2026.
D. A Phase I Utility may only request for review under subsection B project development costs that are (i) associated with the preliminary analysis, testing, and evaluation of a site related to the property to be owned by such Phase I Utility, (ii) associated with the purchase of property to be owned by such Phase I Utility, or (iii) related to siting work on property owned by such Phase I Utility.
E. If a Phase I Utility serves customers in more than one jurisdiction, the percentage of project development costs to be recovered shall be equal to the percentage of associated energy and capacity from the small modular nuclear facility that is assigned to serve customers located in the Commonwealth.
F. As part of a final order approving cost recovery pursuant to this section, the Commission may impose a deadline by which the Phase I Utility shall either (i) place a small modular nuclear facility into commercial operation or (ii) sell the permitted site and return the proceeds of the sale to customers. The length of such deadline shall be at the Commission's discretion; however, it shall provide the utility a reasonable timeframe in which to obtain all necessary permits and approvals, including allowing for approval by federal agencies such as the Nuclear Regulatory Commission, and completing construction of a small modular nuclear facility.
2024, c. 836.
A. After the expiration or termination of capped rates, the rates, terms and conditions of distribution electric cooperatives subject to Article 1 (§ 56-231.15 et seq.) of Chapter 9.1 shall be regulated in accordance with the provisions of Chapters 9.1 (§ 56-231.15 et seq.) and 10 (§ 56-232 et seq.), as modified by the following provisions:
1. Except for energy related cost (fuel cost), the Commission shall not require any cooperative to adjust, modify, or revise its rates, by means of riders or otherwise, to reflect changes in wholesale power cost which occurred during the capped rate period, other than in a general rate proceeding;
2. Each cooperative may, without Commission approval or the requirement of any filing other than as provided in this subdivision, upon an affirmative resolution of its board of directors, increase or decrease all classes of its rates for distribution services at any time, provided, however, that such adjustments will not effect a cumulative net increase or decrease in excess of five percent in such rates in any three-year period. Such adjustments will not affect or be limited by any existing fuel or wholesale power cost adjustment provisions. The cooperative will promptly file any such revised rates with the Commission for informational purposes;
3. Each cooperative may, without Commission approval, upon an affirmative resolution of its board of directors, make any adjustment to its terms and conditions that does not affect the cooperative's revenues from the distribution or supply of electric energy. In addition, a cooperative may make such adjustments to any pass-through of third-party service charges and fees, and to any fees, charges and deposits set out in Schedule F of such cooperative's Terms and Conditions filed as of January 1, 2007. The cooperative will promptly file any such amended terms and conditions with the Commission for informational purposes;
4. Each cooperative may, without Commission approval or the requirement of any filing other than as provided in this subdivision, upon an affirmative resolution of its board of directors, make any adjustment to its rates reasonably calculated to collect any or all of the fixed costs of owning and operating its electric distribution system, including without limitation, such costs as are identified as customer-related costs in a cost of service study, through a new or modified fixed monthly charge, rather than through volumetric charges associated with the use of electric energy or demand, or to rebalance among any of the fixed monthly charge, distribution demand, and distribution energy; however, such adjustments shall be revenue neutral based on the cooperative's determination of the proper intra-class allocation of the revenues produced by its then current rates. If a rate class contains a supply demand charge, the cooperative may rebalance its rate for electricity supply service pursuant to this subdivision. The cooperative may elect, but is not required, to implement such adjustments through incremental changes over the course of up to three years. The cooperative shall file promptly revised tariffs reflecting any such adjustments with the Commission for informational purposes;
5. A cooperative may, at any time after the expiration or termination of capped rates, petition the Commission for approval of one or more rate adjustment clauses for the timely and current recovery from customers of the costs described in subdivisions A 5 b and e of § 56-585.1;
6. A cooperative that is not a current member of a utility aggregation cooperative may at any time petition the Commission for approval of one or more rate adjustment clauses for the timely and current recovery of cost from customers of (i) one or more generation facilities, (ii) one or more major unit modifications of generation facilities, or (iii) one or more pumped hydroelectricity generation and storage facilities. A cooperative seeking a rate adjustment clause pursuant to this subdivision shall have the right, after notice and the opportunity for a hearing, to recover the costs of a facility described in clauses (i), (ii), or (iii) in a rate adjustment clause including construction work in progress and allowance for funds during construction, planning, and development costs of infrastructure associated therewith. The costs of the facility other than projected construction work in progress and allowance for funds used during construction shall not be recovered prior to the date that the facility either (a) begins commercial operation or (b) comes under the ownership of the cooperative. For the purposes of this subdivision, the cooperative's cost of capital shall be recoverable in such a rate adjustment clause and shall be set as either the cooperative's long-term cost of debt or most recent rate of return authorized by the Commission in a rate proceeding. In any proceeding conducted pursuant to this subdivision, the Commission shall consider that all costs expended and revenues recovered arising out of the procurement of generation resources pursuant to this subdivision will inure to the benefit of the general membership of the cooperative. Nothing in this subdivision shall relieve a cooperative from any requirement to obtain a certificate of public convenience and necessity for purposes of constructing generation in the Commonwealth. The Commission's final order regarding any petition filed pursuant to this subdivision shall be entered not more than nine months after the date of filing of such petition. If such petition is approved, the order shall direct that the applicable rate adjustment clause be applied to customers' bills not more than 60 days after the date of the order. Any petition filed pursuant to this subdivision shall be considered by the Commission on a stand-alone basis without regard to the other costs, revenues, investments, or earnings of the cooperative. Any costs incurred by a cooperative prior to the filing of such petition, or during the consideration thereof by the Commission, that are proposed for recovery in such petition, shall be deferred on the books and records of the cooperative until the Commission's final order in the matter, or until the implementation of any applicable approved rate adjustment clause, whichever is later;
7. A cooperative may adopt any other cooperative's voluntary rate, voluntary program (including a pilot program), or voluntary tariff, and cost recovery therefor, by submitting the same to the Commission for administrative approval. The staff of the Commission shall have the authority to approve such administrative filing notwithstanding any other provision of law; and
8. A cooperative may, without approval of the Commission or the requirement of any filing other than as provided in this subsection, upon an affirmative resolution of its board of directors, approve any voluntary tariff, and cost recovery therefor, and shall promptly file any such tariff with the Commission for informational purposes.
B. None of the adjustments described in subdivisions A 2 through A 5 will apply to the rates paid by any customer that takes service by means of dedicated distribution facilities and had noncoincident peak demand in excess of 90 megawatts in calendar year 2006.
C. Nothing in this section shall be deemed to grant to a cooperative any authority to amend or adjust any terms and conditions of service or agreements regarding pole attachments or the use of the cooperative's poles or conduits.
2007, cc. 888, 933; 2009, cc. 401, 824; 2019, cc. 625, 742, 763; 2022, cc. 363, 364.
Distribution electric cooperatives subject to Article 1 (§ 56-231.15 et seq.) of Chapter 9.1 shall be regulated in accordance with the provisions of Chapters 9.1 (§ 56-231.15 et seq.) and 10 (§ 56-232 et seq.), as amended by relevant sections of this chapter and by the following provisions:
1. Notwithstanding anything to the contrary in this title, each cooperative may, without Commission approval or the requirement of any filing other than as provided in this subdivision, upon the adoption by its board of directors of a resolution so providing, make adjustments in the cooperative's rates, terms, conditions, and rate schedules governing net energy metering as provided in this section by electing to subject itself to the provisions of this section. The cooperative promptly shall (i) file such resolution and notice with the Commission for informational purposes and (ii) place a notice of its board of directors' adoption of such resolution (the Cooperative Net Energy Metering Transition Notice) on the cooperative's website. The Cooperative Net Energy Metering Transition Notice shall contain an initial election date and a date upon which, for each class of net energy metering customer, the transition shall become effective upon the first to occur of (a) the date the cooperative reaches the cap set forth in subsection F of § 56-594.01 or (b) five years following the date of the initial Cooperative Net Energy Metering Transition Notice. If a cooperative transitions a given class of customers as a result of reaching a cap set forth in subsection F of § 56-594.01, the effectiveness of such transition shall be permanent, regardless of future changes in the cooperative's system peak. A Cooperative Net Energy Metering Transition Notice may be amended and refiled as the cooperative deems appropriate at any time. Any eligible customer-generator as defined in § 56-594 that was interconnected prior to a transition start date enumerated in a Cooperative Net Energy Metering Transition Notice may continue to participate in net energy metering pursuant to the terms of § 56-594.01 until July 1, 2039.
2. After the transition date for a class of customers, any standby charges implemented by the cooperative pursuant to subsection H of § 56-594.01 shall be eliminated and are prohibited. The cooperative may make any necessary changes to rate schedules or terms and conditions and shall promptly file the same with the Commission for informational purposes.
3. Whenever the cooperative's transition date occurs, the cooperative may establish and publish, without Commission approval or the requirement of any filing other than as provided in this subdivision, a new rate schedule or rider for purposes of its new net energy metering program established pursuant to this section and shall promptly file the same with the Commission for informational purposes.
4. The new rate schedule or rider described in subdivision 3 may contain a demand charge or charges for distribution, supply, or both, based upon a customer's monthly, ratcheted, or 60-minute absolute value noncoincident peak demand for customers that were not previously subject to demand charges in each rate class; however, such demand charges shall be revenue neutral based on the cooperative's determination of the proper intra-class allocation of the revenues produced by its then-current rates serving the same rate class of customer. The cooperative shall implement such new demand charge through the provisions of subdivision 5. The cooperative shall file promptly revised tariffs reflecting any such new demand charges with the Commission for informational purposes. The demand charge component of any net energy metering rate class derived from a rate class with a preexisting demand charge shall remain fixed for a period of five years. The fixed monthly customer charge of any net energy metering rate class derived from a preexisting rate class having a fixed monthly customer charge less than or equal to $20 as of the transition date shall not exceed $20 for the duration of the five-year period described in subdivision 5. During the five-year period described in subdivision 5, a cooperative may not increase the monthly customer charge of any net energy metering rate class derived from a preexisting rate class having a fixed monthly customer charge greater than $20 as of the transition date. Demand charges included in a new rate schedule or rider shall apply to net energy metering customers, regardless of whether a customer uses a third-party partial requirements power purchase agreement or not.
5. For purposes of implementing subdivision 4, a cooperative shall, after the published transition date for a given class of customers, close its existing net energy metering rate schedule rider to new customers and open a new tariff pursuant to subdivision 3. Demand charges shall be implemented over a five-year period. In the first year of the five-year period, the demand charges shall be set to zero. In the second year of the five-year period, implementation of the demand rates may begin, and demand charges shall not exceed $0.25 per kilowatt of distribution demand and $0.25 per kilowatt of supply demand. In the third year of the five-year period, the demand charges shall not exceed $0.50 per kilowatt of distribution demand and $0.50 per kilowatt of supply demand. In the fourth year of the five-year period, the demand charges shall not exceed $0.75 per kilowatt of distribution demand and $0.75 per kilowatt of supply demand. In the fifth year of the five-year period, the demand charges shall not exceed $1 per kilowatt of distribution demand and $1 per kilowatt of supply demand. Following the expiration of the five-year period, the cooperative is authorized to rebalance its rates. In any filing for informational purposes, the cooperative shall clearly set forth to the Commission the schedule for the five-year period.
6. After the transition date for a given class of customers, the following caps, which shall be in lieu of the caps established by subsection F of § 56-594.01, shall apply to net energy metering for that class of customer. The caps shall be calculated as described in subsection F of § 56-594.01 except that the caps shall be adjusted as follows, expressed in alternating current nameplate capacity of the generators: three percent of system peak for residential customers, four percent of system peak for not-for-profit and nonjurisdictional customers, and two percent for other nonresidential customers.
7. After the transition date for a given class of customers, only the following restrictions shall apply to the capacity of a net energy metering electrical generating facility:
a. For nonresidential customers, the maximum capacity shall not exceed the least of:
(1) 1.2 megawatts alternating current;
(2) One percent of the cooperative's system peak calculated according to the methodology described in subsection F of § 56-594.01; or
(3) The expected annual energy consumption based on the previous 12 months of billing history or an annualized calculation of billing history if 12 months of billing history is not available; and
b. For residential customers, the maximum capacity shall not exceed 125 percent of the expected annual energy consumption based on the previous 12 months of billing history or an annualized calculation of billing history if 12 months of billing history is not available.
8. After the transition date for a given class of customers, third-party partial requirements power purchase agreements entered into with registered providers shall be permitted for that class of customer pursuant to subsection K of § 56-594.01.
A. As used in this section:
"Accelerated renewable 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 renewable 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.
"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 renewable 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 renewable 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 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; or (f) 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. 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:
| Phase I Utilities | Phase II Utilities | ||
| Year | RPS Program Requirement | Year | RPS Program Requirement |
| 2021 | 6% | 2021 | 14% |
| 2022 | 7% | 2022 | 17% |
| 2023 | 8% | 2023 | 20% |
| 2024 | 10% | 2024 | 23% |
| 2025 | 14% | 2025 | 26% |
| 2026 | 17% | 2026 | 29% |
| 2027 | 20% | 2027 | 32% |
| 2028 | 24% | 2028 | 35% |
| 2029 | 27% | 2029 | 38% |
| 2030 | 30% | 2030 | 41% |
| 2031 | 33% | 2031 | 45% |
| 2032 | 36% | 2032 | 49% |
| 2033 | 39% | 2033 | 52% |
| 2034 | 42% | 2034 | 55% |
| 2035 | 45% | 2035 | 59% |
| 2036 | 53% | 2036 | 63% |
| 2037 | 53% | 2037 | 67% |
| 2038 | 57% | 2038 | 71% |
| 2039 | 61% | 2039 | 75% |
| 2040 | 65% | 2040 | 79% |
| 2041 | 68% | 2041 | 83% |
| 2042 | 71% | 2042 | 87% |
| 2043 | 74% | 2043 | 91% |
| 2044 | 77% | 2044 | 95% |
| 2045 | 80% | 2045 and thereafter | 100% |
| 2046 | 84% | ||
| 2047 | 88% | ||
| 2048 | 92% | ||
| 2049 | 96% | ||
| 2050 and thereafter | 100% |
2. A Phase II Utility shall meet one percent of 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, with not more than 3,000 kilowatts 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, then no less than 25 percent of such one percent shall be composed of low-income qualifying projects.
3. Beginning with the 2025 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, which shall include 1,100 megawatts of solar generation of a nameplate capacity not to exceed three megawatts per individual project and 35 percent of such generating 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 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 200 megawatts of the 16,100 megawatts shall be placed on previously developed project sites.
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 and wind 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.
4. In connection with the requirements of this subsection, each Phase I and Phase II Utility shall, commencing in 2020 and concluding in 2035, 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 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 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; 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 megawatts hour for resources one megawatt and lower. 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.
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 or acquire new, utility-owned energy storage resources.
1. By December 31, 2035, each Phase I Utility shall petition the Commission for necessary approvals to construct or acquire 400 megawatts of energy storage capacity. Nothing in this subdivision shall prohibit a Phase I Utility from constructing or acquiring more than 400 megawatts of energy storage, provided that 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 construct or acquire 2,700 megawatts of energy storage capacity. Nothing in this subdivision shall prohibit a Phase II Utility from constructing or acquiring more than 2,700 megawatts of energy storage, provided that the utility receives approval from the Commission pursuant to §§ 56-580 and 56-585.1.
3. 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.
4. All energy storage projects procured pursuant to this subsection shall meet the competitive procurement protocols established in subdivision D 3.
5. 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, 2021, 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 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.
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 renewable 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 renewable 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 eligible resources or (ii) bundled capacity, energy, and RECs from solar 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 to or recover from any other customer of the utility the cost of such resources. Such an accelerated renewable energy buyer may offset all or a portion of its electric load for purposes of RPS compliance through such arrangements. An accelerated renewable energy buyer shall be exempt from the assignment of non-bypassable RPS 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 of RECs obtained pursuant to this subsection in proportion to the customer's total electric energy consumption, on an annual basis. An accelerated renewable 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 renewable 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 renewable energy buyer contracts for the capacity of new solar or wind generation resources 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 renewable 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 requirements, and the calculation of the utility's RPS Program requirements shall not include the electric load covered by customers certified as accelerated renewable energy buyers.
2. Each Phase I or Phase II Utility shall certify, and verify as necessary, to the Commission that the accelerated renewable energy buyer has satisfied the exemption requirements of this subsection for each year, or an accelerated renewable 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 renewable energy buyer is allocated to or recovered from any other customer of the utility, any such contract with an accelerated renewable 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.
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) 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.
A. As used in this section:
"Accelerated renewable 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 renewable 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.
"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 renewable 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 renewable 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 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; or (e) 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.
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:
| Phase I Utilities | Phase II Utilities | ||
| Year | RPS Program Requirement | Year | RPS Program Requirement |
| 2021 | 6% | 2021 | 14% |
| 2022 | 7% | 2022 | 17% |
| 2023 | 8% | 2023 | 20% |
| 2024 | 10% | 2024 | 23% |
| 2025 | 14% | 2025 | 26% |
| 2026 | 17% | 2026 | 29% |
| 2027 | 20% | 2027 | 32% |
| 2028 | 24% | 2028 | 35% |
| 2029 | 27% | 2029 | 38% |
| 2030 | 30% | 2030 | 41% |
| 2031 | 33% | 2031 | 45% |
| 2032 | 36% | 2032 | 49% |
| 2033 | 39% | 2033 | 52% |
| 2034 | 42% | 2034 | 55% |
| 2035 | 45% | 2035 | 59% |
| 2036 | 53% | 2036 | 63% |
| 2037 | 53% | 2037 | 67% |
| 2038 | 57% | 2038 | 71% |
| 2039 | 61% | 2039 | 75% |
| 2040 | 65% | 2040 | 79% |
| 2041 | 68% | 2041 | 83% |
| 2042 | 71% | 2042 | 87% |
| 2043 | 74% | 2043 | 91% |
| 2044 | 77% | 2044 | 95% |
| 2045 | 80% | 2045 and thereafter | 100% |
| 2046 | 84% | ||
| 2047 | 88% | ||
| 2048 | 92% | ||
| 2049 | 96% | ||
| 2050 and thereafter | 100% |
A Phase II Utility shall meet one percent of 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, with not more than 3,000 kilowatts 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, then no less than 25 percent of such one percent shall be composed of low-income qualifying projects.
Beginning with the 2025 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.
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.
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, which shall include 1,100 megawatts of solar generation of a nameplate capacity not to exceed three megawatts per individual project and 35 percent of such generating 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 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 200 megawatts of the 16,100 megawatts shall be placed on previously developed project sites.
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 and wind 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.
4. In connection with the requirements of this subsection, each Phase I and Phase II Utility shall, commencing in 2020 and concluding in 2035, 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 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 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, 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 megawatts hour for resources one megawatt and lower. 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.
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 or acquire new, utility-owned energy storage resources.
1. By December 31, 2035, each Phase I Utility shall petition the Commission for necessary approvals to construct or acquire 400 megawatts of energy storage capacity. Nothing in this subdivision shall prohibit a Phase I Utility from constructing or acquiring more than 400 megawatts of energy storage, provided that 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 construct or acquire 2,700 megawatts of energy storage capacity. Nothing in this subdivision shall prohibit a Phase II Utility from constructing or acquiring more than 2,700 megawatts of energy storage, provided that the utility receives approval from the Commission pursuant to §§ 56-580 and 56-585.1.
3. 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.
4. All energy storage projects procured pursuant to this subsection shall meet the competitive procurement protocols established in subdivision D 3.
5. 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, 2021, 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 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.
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 renewable 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 renewable 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 eligible resources or (ii) bundled capacity, energy, and RECs from solar 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 to or recover from any other customer of the utility the cost of such resources. Such an accelerated renewable energy buyer may offset all or a portion of its electric load for purposes of RPS compliance through such arrangements. An accelerated renewable energy buyer shall be exempt from the assignment of non-bypassable RPS 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 of RECs obtained pursuant to this subsection in proportion to the customer's total electric energy consumption, on an annual basis. An accelerated renewable 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 renewable 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 renewable energy buyer contracts for the capacity of new solar or wind generation resources 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 renewable 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 requirements, and the calculation of the utility's RPS Program requirements shall not include the electric load covered by customers certified as accelerated renewable energy buyers.
2. Each Phase I or Phase II Utility shall certify, and verify as necessary, to the Commission that the accelerated renewable energy buyer has satisfied the exemption requirements of this subsection for each year, or an accelerated renewable 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 renewable energy buyer is allocated to or recovered from any other customer of the utility, any such contract with an accelerated renewable 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.
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) 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, c. 596.
A. The Commission shall, after notice and opportunity for hearing, initiate a proceeding to establish the rates, terms, and conditions of a non-bypassable universal service fee to fund the Percentage of Income Payment Program (PIPP). Such universal service fee shall be allocated to retail electric customers of a Phase I and Phase II Utility on the basis of the amount of kilowatt-hours used and be established at such level to adequately address the PIPP's objectives to (i) reduce the energy burden of eligible participants by limiting electric bill payments directly to no more than six percent of the eligible participant's annual household income if the household's heating source is anything other than electricity, and to no more than 10 percent of an eligible participant's annual household income on electricity costs if the household's primary heating source is electricity; (ii) reduce the amount of electricity used by the eligible participant's household through participation in weatherization or energy efficiency programs and energy conservation education programs; and (iii) reduce the amount of energy, regardless of primary heating source, used by the eligible participant's household through participation in weatherization or energy efficiency programs and energy conservation education programs. The annual total cost of any programs implemented pursuant to clauses (i), (ii), and (iii) shall not exceed costs, including administrative costs, in the aggregate of (a) $25 million for any Phase I Utility or (b) $100 million for any Phase II Utility in any rate year in which such program costs are incurred.
B. The Commission shall determine the reasonable administrative costs for the investor-owned utility to collect the universal service fee and remit such funds to the Percentage of Income Payment Fund established in subsection E, and any other administrative costs the investor-owned utility may incur in complying with the PIPP, and shall determine the proper recovery mechanism for such costs. A Phase I and Phase II Utility shall not be eligible to earn a rate of return on any equity or costs incurred to comply with the program requirements or implementation. The Commission shall initiate proceedings to provide for an annual true-up of the universal service fee within 60 days of the commencement of the PIPP and on an annual or semiannual basis thereafter. As part of any annual true-up case, each Phase I and Phase II Utility shall report to the Commission any data or forecasting required by the Commission regarding the participation by PIPP participants in utility energy reduction programs.
C. The Department of Social Services (the Department), in consultation with, as it deems necessary, the Department of Housing and Community Development, shall adopt rules or establish guidelines for the adoption, implementation, and general administration of the PIPP and the Percentage of Income Payment Fund established in subsection E, consistent with this section. Such rules or guidelines shall include exemptions for terms of program participation or energy use reduction as the Department deems appropriate. The PIPP shall commence no later than one year after the Department publishes such rules or guidelines. Each Phase I and Phase II Utility shall cooperate with the requests of the Department in the implementation and administration of the PIPP. The Commission shall promulgate any rules necessary to ensure that (i) funds collected from each utility's universal service fee are directed to the Percentage of Income Payment Fund and (ii) utilities receive adequate compensation from the Fund, on a timely basis, for all reasonable costs of the PIPP, including costs associated with bill payment credits for eligible customers.
D. In carrying out the PIPP's objective of electricity usage reductions, PIPP-eligible customers may, to the extent reasonably possible, utilize existing energy efficiency or related programs approved by the Commission for a Phase I and Phase II Utility and existing and available federal, state, local, or nonprofit programs. The Department may review the needs of PIPP-eligible customers and whether gaps remain in serving such customers that are not already served by existing and available federal, state, local, or nonprofit programs to meet the energy reduction obligations of this section. The Department shall report the results of such analysis and review to the Chairs of the House Committee on Labor and Commerce and the Senate Committee on Commerce and Labor no later than November 1, 2022.
E. There is hereby created in the state treasury a special nonreverting fund to be known as the Percentage of Income Payment Fund, referred to in this section as "the Fund." The Fund shall be established on the books of the Comptroller. All funds collected from each Phase I and Phase II Utility's universal service fee shall be paid into the state treasury and credited to the Fund. Interest earned on moneys in the Fund shall remain in the Fund and be credited to it. Any moneys remaining in the Fund, including interest thereon, at the end of each fiscal year shall not revert to the general fund but shall remain in the Fund. Moneys in the Fund shall be used solely for the purposes of implementation and administration of the PIPP, including any associated start-up costs. Expenditures and disbursements from the Fund shall be made by the State Treasurer on warrants issued by the Comptroller upon written request signed by the Commissioner of the Department of Social Services or by order of the Commission in conjunction with a true-up proceeding.
A. As used in this section:
"Cooperative" means a utility consumer services cooperative.
"Eligible customer" means a member-consumer receiving service from a cooperative that (i) has asked to participate in the cooperative's on-bill tariff program and (ii) has been determined by the cooperative to be eligible to participate in its on-bill tariff program.
"Energy efficiency measures" means any installation, improvement, addition, or equipment approved by the cooperative for purpose of its on-bill tariff program that has the primary purpose of improving the energy efficiency of the premises and reducing its consumption of energy, including heating and air conditioning systems, water heaters, weatherization, insulation, window and door modifications, appliances, and automatic or Internet-connected energy control systems. "Energy efficiency measures" does not include (i) energy conservation measures to improve the energy efficiency of premises constructed within five years prior to an eligible customer's request to participate in an on-bill tariff program or premises that are under initial construction or (ii) the electrification of any process or activity primarily fueled by natural gas.
"Energy savings charge" means the charge placed by the cooperative on the monthly billing statement of an eligible customer or subsequent customers in order to recover the costs of the energy efficiency measures installed at the eligible customer's premises.
"On-bill tariff agreement" means an agreement between an eligible customer and a cooperative that provides for the terms, conditions, payments, and costs, including financing or capital costs, of the installation of energy efficiency measures at a premises to be paid by or through the cooperative and repaid by the eligible customer or subsequent customer at the same premises by means of an energy savings charge.
"On-bill tariff program" means a voluntary tariff program that allows eligible customers (i) to arrange through the cooperative for its provision and installation, including by its chosen vendors, of energy efficiency measures at the customer's premises without an upfront payment and (ii) to pay back over time the cost of the energy efficiency measures through an energy savings charge.
"Program costs" means a participating cooperative's (i) identified, projected, and actual costs to design, implement, and operate its on-bill tariff program, including costs to request and evaluate vendor proposals and manage the vendors; (ii) administrative, labor, and marketing charges; (iii) costs of obtaining funds used by the cooperative to pay for the energy efficiency measures; (iv) write-offs for unpaid energy savings charges after reasonable collection efforts; and (v) reasonable margin.
B. On or after January 1, 2021, notwithstanding any other provision of law, a cooperative may, without Commission approval, upon an affirmative resolution of its board of directors and without the requirement of any filing other than as required in this subsection, propose, establish, and implement an on-bill tariff program for energy efficiency measures, provided that such program adheres to the provisions of this section. This regulated, tariffed program shall be reviewable by the Commission at the cooperative's next general rate proceeding. A cooperative shall recover the program costs through a new rate schedule established by this section or otherwise through its rates. A cooperative shall file a copy of any such new rate schedule with the Commission for informational purposes.
C. At least 120 days prior to making an informational filing as described in subsection B, a cooperative shall conduct a stakeholder process to design the on-bill tariff program collaboratively with interested parties. Such stakeholder process shall be open to the cooperative's membership and invited guests and shall include an opportunity to participate for low-income and middle-income advocates, energy efficiency advocates, affordable housing advocates, and the staff of the Commission. The stakeholder process shall examine and recommend, among other things, appropriate additional consumer safeguards for potential adoption by the cooperative, including oversight of third-party vendors and appropriate methods for notifying customers that vendors are subject to the Virginia Consumer Protection Act (§ 59.1-196 et seq.). The stakeholder process shall allow for remote or electronic participation and may include multiple cooperatives or be coordinated, convened, and facilitated by a group or association of cooperatives. The meetings of the stakeholders may be held anywhere in the Commonwealth. The cooperative shall include documentation concerning the stakeholder process in its informational filing to the Commission.
D. A cooperative's on-bill tariff program shall include criteria for selecting eligible customers; limits on the individual and aggregate amounts of energy efficiency measures for each eligible customer; limits on the overall amount available under the on-bill tariff program; generally applicable repayment terms; and qualifications of potential vendors that will market or install energy efficiency measures. Multiple cooperatives may collaborate to create a similar structure for on-bill tariff programs.
E. An on-bill tariff agreement shall:
1. Specify that the eligible customer or subsequent customers at the premises shall only be responsible for the payment of the energy savings charge upon satisfactory installation of the energy efficiency measures as set forth in their on-bill tariff agreement;
2. Specify that the cooperative may recover the costs, including financing or capital costs, of installing the energy efficiency measures at an eligible customer's premises through the energy savings charge;
3. Provide for the inclusion of an energy savings charge that is stated as a separate line item on the eligible customer's or subsequent customer's utility bill;
4. Provide that an eligible customer shall enter into an on-bill tariff agreement to participate in the on-bill tariff program;
5. Provide that the cooperative may apply the energy savings charge to the meter or bill of subsequent customers at the premises and that the then-current eligible customer is required to notify the subsequent customer of the on-bill tariff agreement and the energy savings charge;
6. Deem amounts due under the tariff to be amounts owed for regulated electric service and for which an eligible customer is subject to disconnection of service pursuant to the cooperative's existing policies for disconnection;
7. Provide that any loan or financing interest rate or cost of capital, or their equivalent, that is provided to the eligible customer pursuant to an on-bill tariff agreement shall be less than prevailing market rates;
8. Provide that payments for energy-saving charges made by eligible and subsequent customers shall be retained by the cooperative and amounts credited against the appropriate category of program costs; and
9. Result in deemed savings that are reasonably projected, based on the customer's energy utilization and rates at the beginning of the term, to result in lower energy bills for the customer, and that allocate a portion of the gross cost savings resulting from the energy efficiency measures to the eligible customer and the remaining portion to the cooperative to recover the program costs.
F. Customers having a grievance or complaints against an on-bill tariff program shall have recourse to the informal and formal procedures of the Commission.
A. For the purposes of this section:
"Phase I Utility" has the same meaning as provided in subdivision A 1 of § 56-585.1.
"Utility" means a Phase I Utility.
B. With the first review commencing on March 31, 2024, and biennially thereafter, the Commission shall conduct rate reviews of the rates, terms, and conditions for the provision of generation and distribution services by a Phase I Utility that participated in triennial review proceedings in 2020 and 2023, and such Phase I Utility shall no longer be subject to triennial review proceedings pursuant to § 56-585.1.
C. In each biennial review, the Commission shall conduct a proceeding to review all rates, terms, and conditions for generation and distribution services with such proceeding utilizing the two successive 12-month test periods ending December 31 immediately preceding the year in which such proceeding is conducted. Such biennial review shall be conducted in a single, combined proceeding, except for review of the following costs, which the utility shall continue to recover and the Commission shall continue to review separately, pursuant to the applicable statutory provisions: costs that are recovered pursuant to (i) § 56-249.6, (ii) subdivisions A 4, 5, and 6 of § 56-585.1, and (iii) § 56-585.6.
D. Each biennial rate review proceeding shall commence on or before March 31 of the biennial review year with the filing of a petition by each Phase I Utility subject to the provisions of this section. The Commission, after providing notice and an opportunity for hearing, shall grant a final order on such petition no later than November 20. Any revisions in rates ordered by the Commission pursuant to the rate review shall take effect no later than January 1 of the subsequent year.
E. In each biennial review proceeding, the Commission shall set the fair rate of return on common equity applicable to the generation and distribution services of the utility for the two such services combined and for any rate adjustment clauses approved under subdivision A 5 or 6 of § 56-585.1. The Commission may use any methodology it finds consistent with the public interest to determine the Phase I Utility's fair rate of return on common equity. The Commission may increase or decrease the combined rate of return for generation and distribution services by up to 50 basis points based on factors that may include reliability, generating plant performance, customer service, and operating efficiency of a utility. Any such adjustment to the combined rate of return for generation and distribution services shall include consideration of nationally recognized standards determined by the Commission to be appropriate for such purposes.
F. In any biennial review for a Phase I Utility, if the Commission determines in its sole discretion that the utility's existing rates for generation and distribution services will, on a going-forward basis, either produce (i) revenues in excess of the utility's authorized rate of return or (ii) revenues below the utility's authorized rate of return, then the Commission shall order any reductions or increases, as applicable and necessary, to such rates for generation and distribution services that it deems appropriate to ensure the resulting rates for generation and distribution services (a) are just and reasonable and (b) provide the utility an opportunity to recover its costs of providing services over the rate period ending on December 31 of the year of the utility's succeeding review and earn a fair rate of return authorized pursuant to this section. Such determination shall be limited to the Phase I Utility's rates for generation and distribution services and shall not consider the costs or revenues recovered in any rate adjustment clause authorized pursuant to this chapter.
G. In any biennial review of rates for generation and distribution services, if the combined rate of return on common equity earned is no more than 100 basis points above or below the fair combined rate of return, as determined by the Commission, for the test period under review, then such combined return shall not be considered either excessive or insufficient, respectively.
1. If in any biennial review, the Commission finds that, during the test period under review, considered as a whole, the utility has earned more than 100 basis points above the authorized fair combined rate of return on its generation or distribution services, the Commission shall direct that 100 percent of the amount of such earnings that were more than 100 basis points above such fair combined rate of return for the test period under review, considered as a whole, be credited to customers' bills. Any such credits shall be applied to customers' bills, as determined at the discretion of the Commission, following the effective date of the Commission's order, and shall be allocated among customer classes such that the relationship between the specific customer class rates of return to the overall target rate of return will have the same relationship as the last approved allocation of revenues used to design base rates; or
2. The Commission shall authorize deferred recovery for reasonable (i) actual costs associated with severe weather events and (ii) actual costs associated with natural disasters, not currently in rates, and the Commission shall allow the utility to amortize and recover such deferred costs over future periods as determined by the Commission. The amount of any such deferral shall not exceed an amount that would, together with the utility's other costs, revenues, and investments recovered through rates for generation and distribution services for the test period under review, cause the utility's earned return on its generation and distribution services to exceed 100 basis points above the fair combined rate of return applicable to the test period under review. For the purposes of determining any amount of costs that are associated with severe weather events, the Commission shall consider nationally recognized standards such as those published by the Institute of Electrical and Electronics Engineers (IEEE).
Any amount of a utility's earnings directed by the Commission to be credited to customers' bills pursuant to this subsection shall not be considered for the purpose of determining the utility's earnings in any subsequent biennial review.
H. In any proceeding under this title, including each biennial review, to determine the prior two years' excess or deficiency for the purposes of subsection F, the Commission shall use an average rate base using the actual starting and end-of-test period capital structure of the utility, excluding any debt associated with any securitized bonds and without regard to the cost of capital, capital structure, or investments of any other entities with which the utility is affiliated. To determine a revenue requirement in any proceeding under this title, the Commission shall use the utility's actual end-of-test period capital structure and cost of capital without regard to the cost of capital, capital structure, or investments of any other entities with which the utility is affiliated, including debt associated with any securitized bonds, unless the Commission makes a finding, based on evidence in the record, that the debt to equity ratio of the actual end-of-test period capital structure of such utility is unreasonable, in which case the Commission may utilize a debt to equity ratio that it finds to be reasonable.
In a rate review for a Phase I Utility that is part of a publicly traded, consolidated group, the Commission shall determine federal and state income tax costs as follows: (i) the utility's apportioned state income tax costs shall be calculated according to the applicable statutory rate, as if the utility had not filed a consolidated return with its affiliates, and (ii) the utility's federal income tax costs shall be calculated according to the applicable federal income tax rate and shall exclude any consolidated tax liability or benefit adjustments originating from any taxable income or loss of its affiliates.
I. The Commission is authorized to determine during any biennial review the reasonableness or prudence of any cost subject to the rate review incurred or projected to be incurred by the utility, and a Phase I Utility shall recover such costs that the Commission finds to be reasonable and prudent.
J. In any biennial review conducted pursuant to this section, a Phase I Utility or any other party may propose changes to its terms and conditions and the Commission may approve, reject, or amend any changes and may propose any special rates, contracts, or incentives pursuant to § 56-235.2.
K. Nothing in this section shall alter a Phase I Utility's obligations pursuant to §§ 56-585.5 and 56-596.2.
L. To the extent that the provisions of this section are inconsistent with the provisions of § 56-585.1, the provisions of this section shall control.
On and after January 1, 2001, if any supplier fails to fulfill an obligation, resulting in the failure of retail electric energy to be delivered into the control area serving the supplier's retail customer, the entity fulfilling the control area function, or, if applicable, the regional transmission entity or other entity as designated by the Commission, shall be responsible for charging the defaulting supplier for the full cost of replacement energy, including the cost of energy, the cost incurred by others as a result of the default, and the assessment of penalties as may be approved either by the Commission, to the extent not precluded by federal law, or by the Federal Energy Regulatory Commission. The Commission, as part of the rules established under § 56-587, shall determine the circumstances under which failures to deliver electricity will result in the revocation of the supplier's license.
1999, c. 411.
A. As used in this section, "electric energy emergency" means an unplanned interruption in the generation or transmission of electricity resulting from a hurricane, ice storm, windstorm, earthquake or similar natural phenomena, or from a criminal act affecting such generation or transmission, act of war or act of terrorism, which interruption is (i) of such severity that minimum levels of reliable service cannot be maintained using resources practicably obtainable from the market and (ii) so imminently and substantially threatening to the health, safety or welfare of residents of this Commonwealth that immediate action of state government is necessary to prevent loss of life, protect the public health or safety, and prevent unnecessary or avoidable damage to property.
B. The Governor is authorized, after finding that an electric energy emergency exists and that appropriate federal and state agencies and appropriate reliability councils cannot adequately address such emergency, to declare an electric energy emergency by filing a written declaration with the Secretary of the Commonwealth. The declaration shall state the counties and cities or utility service areas of the Commonwealth in which the declaration is applicable, or its statewide application. A declared electric energy emergency shall go into immediate effect upon filing and continue in effect for the period prescribed in the declaration, but not more than thirty days. At the end of the prescribed period, the Governor may issue another declaration extending the emergency. The Governor shall terminate such declaration as soon as the basis for such declaration no longer exists.
C. During a declared electric energy emergency, the Governor is authorized, in compliance with guidelines of the Department of Emergency Services promulgated as provided in subsection G, to require any generator or any municipal electric utility that is capable of generating but (i) is not generating or (ii) is not generating at its full potential during such declared electric emergency, to generate, dispatch or sell electricity from a facility that it operates within the Commonwealth, to the Commonwealth for distribution within the areas of the Commonwealth designated in the declaration. The quantity of electricity required to be generated, dispatched or sold, and the duration of such requirements, shall be as determined by the Governor to be necessary to alleviate the electric energy emergency hardship. The Commonwealth shall compensate an entity required to generate, dispatch, or sell electricity pursuant to this subsection, and the operator of any transmission facilities over which the electricity is transmitted, in the manner provided in § 56-522, mutatis mutandis, unless otherwise provided by federal law. The Department of Environmental Quality, the State Air Pollution Control Board, the State Water Control Board, and the Virginia Waste Management Board shall issue any temporary or emergency permit, order, or variance necessary to authorize any permit amendments or other changes needed to meet the requirements imposed under this section and the Governor may petition the President to declare a regional energy emergency under 42 U.S.C. § 7410 (f) as necessary to suspend enforcement of any provision of the federal Clean Air Act. Any increased operation required during such declared emergency shall not be counted towards the number of hours of operation allowed during the year. No civil charges or penalties shall be imposed for any violation that occurs as a result of actions taken that are necessary for the required generation, dispatch or sale during the declared electric energy emergency. The foregoing provisions shall apply to all actions the entity takes in connection with such required generation, dispatch or sale during the period of the declared emergency.
D. During a declared electric energy emergency, the Governor may use the services, equipment, supplies, and facilities of existing departments, offices, and agencies of the Commonwealth, and of the political subdivisions thereof, to the maximum extent practicable and necessary to meet the electric energy emergency. The officers and personnel of all such departments, offices, and agencies shall cooperate with and extend such services and facilities to the Governor upon request.
E. During a declared electric energy emergency, the Governor is authorized to request the Secretary of the United States Department of Energy to invoke section 202(C) of the Federal Power Act, 16 U.S.C. § 824a (1935).
F. The General Assembly is authorized by joint resolution to terminate any declaration of an electric energy emergency. The emergency shall be terminated at the time of filing of the joint resolution with the Secretary of the Commonwealth.
G. The Department of Emergency Services, in consultation with the Commission and the Secretary of Commerce and Trade, shall establish guidelines for the implementation of the Governor's powers pursuant to subsection C that protect the public health and safety and prevent unnecessary or avoidable damage to property with a minimum of economic disruption to generators, transmitters and distributors of electricity. Such guidelines shall:
1. Define various foreseeable levels of electric energy emergencies and specify appropriate measures to be taken for each type of electric energy emergency as necessary to protect the public health or safety or prevent unnecessary or avoidable damage to property;
2. Prescribe appropriate response measures for each level of electric energy emergency; and
3. Equitably distribute the burdens and benefits resulting from the implementation of this section among other members of the affected class of persons within all geographic regions of the Commonwealth.
H. During a declared electric energy emergency, the attorney general may bring an action for injunctive or other appropriate relief in the Circuit Court of the City of Richmond to secure prompt compliance. The court may issue an ex parte temporary order without notice that shall enforce the prohibitions, restrictions or actions that are necessary to secure compliance with the guideline, order or declaration.
I. During a declared electric energy emergency, no person shall intentionally violate any guideline adopted or declaration issued pursuant to this section. Any person who violates this section is guilty of a Class 1 misdemeanor.
2002, c. 609.
A. As a condition of doing business in the Commonwealth, each person except a default service provider seeking to sell, offering to sell, or selling electric energy to any retail customer in the Commonwealth, on and after January 1, 2002, shall obtain a license from the Commission to do so. A license shall not be required solely for the leasing or financing of property used in the sale of electricity to any retail customer in the Commonwealth.
The license shall authorize that person to engage in the activities authorized by such license until the license expires or is otherwise terminated, suspended or revoked.
B. 1. As a condition of obtaining, retaining and renewing any license issued pursuant to this section, a person shall satisfy such reasonable and nondiscriminatory requirements as may be specified by the Commission, which may include requirements that such person (i) demonstrate, in a manner satisfactory to the Commission, financial responsibility; (ii) post a bond as deemed adequate by the Commission to ensure that financial responsibility; (iii) pay an annual license fee to be determined by the Commission; and (iv) pay all taxes and fees lawfully imposed by the Commonwealth or by any municipality or other political subdivision of the Commonwealth. In addition, as a condition of obtaining, retaining and renewing any license pursuant to this section, a person shall satisfy such reasonable and nondiscriminatory requirements as may be specified by the Commission, including but not limited to requirements that such person demonstrate (i) technical capabilities as the Commission may deem appropriate; (ii) in the case of a person seeking to sell, offering to sell, or selling electric energy to any retail customer in the Commonwealth, access to generation and generation reserves; and (iii) adherence to minimum market conduct standards.
2. Any license issued by the Commission pursuant to this section to a person seeking to sell, offering to sell, or selling electric energy to any retail customer in the Commonwealth may be conditioned upon the licensee furnishing to the Commission prior to the provision of electric energy to consumers proof of adequate access to generation and generation reserves.
C. The Commission:
1. Shall establish a reasonable period within which any retail customer may cancel, without penalty or cost, any contract entered into with any person licensed pursuant to this section; and
2. May adopt other rules and regulations governing the requirements for obtaining, retaining, and renewing a license issued pursuant to this section, and may, as appropriate, refuse to issue a license to, or suspend, revoke, or refuse to renew the license of, any person that does not meet those requirements.
D. Each licensed supplier serving customers of a Phase I Utility, as defined in subdivision A 1 of § 56-585.1, shall file a report, verified by the president or the equivalent executive of such supplier, with the Commission by March 31 of each year that contains:
1. Copies of all marketing materials and other public information conveyed to potential customers regarding the services offered by the supplier;
2. Usage and revenue data for the most recent year submitted to the U.S. Energy Information Administration;
3. Copies of all agreements entered into during the previous calendar year with such customers taking service under subdivision A 3 of § 56-577. Such agreements may be filed under seal, and if so will be afforded confidential treatment and will not be disclosed beyond the Commission or its staff; and
4. A statement that the agreements submitted comply with the Commission's Rules Governing Retail Access to Competitive Energy Services (20VAC5-312-10 et seq.).
Failure to provide such report may be grounds for suspension or revocation of the supplier's license to sell retail electric energy within the Commonwealth.
E. Notwithstanding the provisions of § 13.1-620, a public service company may, through an affiliate or subsidiary, conduct one or more of the following businesses, even if such business is not related to or incidental to its stated business as a public service company: (i) become licensed as a retail electric energy supplier pursuant to this section, or for purposes of participation in an approved pilot program encompassing retail customer choice of electric energy suppliers; (ii) become licensed as an aggregator pursuant to § 56-588, or for purposes of participation in an approved pilot program encompassing retail customer choice of electric energy suppliers; or (iii) own, manage or control any plant or equipment or any part of a plant or equipment used for the generation of electric energy.
1999, c. 411; 2000, c. 991; 2007, cc. 888, 933; 2019, c. 833.
A. As a condition of doing business in the Commonwealth, each person seeking to act as an aggregator within this Commonwealth on and after January 1, 2002, shall obtain a license from the Commission to do so. The license shall authorize that person to act as an aggregator until the license expires or is otherwise terminated, suspended or revoked. Licensing pursuant to this section, however, shall not relieve any person seeking to act as a supplier of electric energy from their obligation to obtain a license as a supplier pursuant to § 56-587.
B. As a condition of obtaining, retaining and renewing any license issued pursuant to this section, a person shall satisfy such reasonable and nondiscriminatory requirements as may be specified by the Commission, which may include requirements that such person (i) provide background information; (ii) demonstrate, in a manner satisfactory to the Commission, financial responsibility; (iii) post a bond as deemed adequate by the Commission to ensure that financial responsibility; (iv) pay an annual license fee to be determined by the Commission; and (v) pay all taxes and fees lawfully imposed by the Commonwealth or by any municipality or other political subdivision of the Commonwealth. In addition, as a condition of obtaining, retaining and renewing any license pursuant to this section, a person shall satisfy such reasonable and nondiscriminatory requirements as may be specified by the Commission, including, but not limited to, requirements that such person demonstrate technical capabilities as the Commission may deem appropriate. Any license issued by the Commission pursuant to this section may be conditioned upon the licensee, if acting as a supplier, furnishing to the Commission prior to the provision of electricity to consumers proof of adequate access to generation and generation reserves.
C. In establishing aggregator licensing schemes and requirements applicable to the same, the Commission may differentiate between (i) those aggregators representing retail customers only, (ii) those aggregators representing suppliers only, and (iii) those aggregators representing both retail customers and suppliers.
D. 1. The Commission shall establish a reasonable period within which any retail customer may cancel, without penalty or cost, any contract entered into with an aggregator licensed pursuant to this section.
2. The Commission may adopt other rules and regulations governing the requirements for obtaining, retaining, and renewing a license to aggregate electric energy to retail customers, and may, as appropriate, refuse to issue a license to, or suspend, revoke, or refuse to renew the license of, any person that does not meet those requirements.
A. Subject to the provisions of subdivision A 3 of § 56-577, counties, cities, and towns (hereafter municipalities) and other political subdivisions of the Commonwealth may, at their election and upon authorization by majority votes of their governing bodies, aggregate electrical energy and demand requirements for the purpose of negotiating the purchase of electrical energy requirements from any licensed supplier within this Commonwealth, as follows:
1. Any municipality or other political subdivision of the Commonwealth may aggregate the electric energy load of residential, commercial, and industrial retail customers within its boundaries on an opt-in or opt-out basis.
2. Any municipality or other political subdivision of the Commonwealth may aggregate the electric energy load of its governmental buildings, facilities, and any other governmental operations requiring the consumption of electric energy. Aggregation pursuant to this subdivision shall not require licensure pursuant to § 56-588.
3. Two or more municipalities or other political subdivisions within the Commonwealth may aggregate the electric energy load of their governmental buildings, facilities, and any other governmental operations requiring the consumption of electric energy. Aggregation pursuant to this subdivision shall not require licensure pursuant to § 56-588 when such municipalities or other political subdivisions are acting jointly to negotiate or arrange for themselves agreements for their energy needs directly with licensed suppliers or aggregators.
Nothing in this subsection shall prohibit the Commission's development and implementation of pilot programs for opt-in, opt-out, or any other type of municipal aggregation, as provided in § 56-577.
B. The Commonwealth, at its election, may aggregate the electric energy load of its governmental buildings, facilities, and any other government operations requiring the consumption of electric energy for the purpose of negotiating the purchase of electricity from any licensed supplier within the Commonwealth. Aggregation pursuant to this subsection shall not require licensure pursuant to § 56-588.
C. Nothing in this section shall preclude municipalities from aggregating the electric energy load of their governmental buildings, facilities and any other governmental operations requiring the consumption of electric energy for the purpose of negotiating rates and terms, and conditions of service from the electric utility certificated by the Commission to serve the territory in which such buildings, facilities and operations are located, provided, however, that no such electric energy load shall be aggregated for this purpose unless all such buildings, facilities and operations to be aggregated are served by the same electric utility.
1999, c. 411; 2000, c. 991; 2003, c. 795; 2004, c. 827; 2007, cc. 888, 933.
A. A school board of a school division located in a locality that is a non-jurisdictional customer of a utility pursuant to § 56-234 and that owns or operates a public school building or facility that has been modernized consistent with Article 3 (§ 22.1-141.1 et seq.) of Chapter 9 of Title 22.1 and generates energy derived from sunlight and the solar generating facility is interconnected pursuant to § 56-594 may enter into a contract to generate such energy on terms and conditions negotiated between the customer and the utility.
B. The solar-powered renewable energy generation facilities associated with a public school building or facility owned or operated by a school board shall be located on the same real property upon which the public school buildings and facilities are located. The solar facilities shall be located on the rooftops of the public school buildings and facilities, however up to 20 percent of the capacity may come from ground mounted solar facilities.
C. Neither jurisdictional customers nor non-jurisdictional customers that do not participate in a school modernization project consistent with Article 3 (§ 22.1-141.1 et seq.) of Chapter 9 of Title 22.1 shall bear any costs associated with such school modernization project by a participating non-jurisdictional customer.
A. The Commission shall not require any incumbent electric utility to divest itself of any generation, transmission or distribution assets pursuant to any provision of this chapter.
B. 1. The Commission shall, however, direct the functional separation of generation, retail transmission and distribution of all incumbent electric utilities in connection with the provisions of this chapter to be completed by January 1, 2002.
2. By January 1, 2001, each incumbent electric utility shall submit to the Commission a plan for such functional separation which may be accomplished through the creation of affiliates, or through such other means as may be acceptable to the Commission.
3. Consistent with this chapter, the Commission may impose conditions, as the public interest requires, upon its approval of any incumbent electric utility's plan for functional separation, including requirements that (i) the incumbent electric utility's generation assets or, at the election of the incumbent electric utility and if approved by the Commission pursuant to subdivision 4 of this subsection, their equivalent are made available for electric service during the capped rate period as provided in § 56-582 and, if applicable, during any period the distributor serves as a default provider as provided for in § 56-585; (ii) the incumbent electric utility receive Commission approval for the sale, transfer or other disposition of generation assets during the capped rate period and, if applicable, during any period the distributor serves as a default provider; and (iii) any such generation asset sold, transferred, or otherwise disposed of by the incumbent electric utility with Commission approval shall not be further sold, transferred, or otherwise disposed of during the capped rate period and, if applicable, during any period the distributor serves as default provider, without additional Commission approval.
4. If an incumbent electric utility proposes that the equivalent to its generation assets be made available pursuant to subdivision 3 of this subsection, the Commission shall determine the adequacy of such proposal and shall approve or reject such proposal based on the public interest.
5. In exercising its authority under the provisions of this section and under § 56-90, the Commission shall have no authority to regulate, on a cost-of-service basis or other basis, the price at which generation assets or their equivalent are made available for default service purposes. Such restriction on the Commission's authority to regulate, on a cost-of-service basis or other basis, prices for default service shall not affect the ability of a distributor to offer to provide, and of the Commission to approve if appropriate the provision of, such services on a cost plus basis or any other basis. The Commission's authority to regulate the price of default service shall be consistent with the pricing provisions applicable to a distributor pursuant to § 56-585. In addition, the Commission shall, in exercising its responsibilities under this section and under § 56-90, consider, among other factors, the potential effects of any such transfer on: (i) rates and reliability of capped rate service under § 56-582, and of default service under § 56-585, and (ii) the development of a competitive market in the Commonwealth for retail generation services. However, the Commission may not deny approval of a transfer proposed by an incumbent electric utility, pursuant to subdivisions 2 and 4 of this subsection, due to an inability to determine, at the time of consideration of the transfer, default service prices under § 56-585.
C. The Commission shall, to the extent necessary to promote effective competition in the Commonwealth, promulgate rules and regulations to carry out the provisions of this section, which rules and regulations shall include provisions:
1. Prohibiting cost-shifting or cross-subsidies between functionally separate units;
2. Prohibiting functionally separate units from engaging in anticompetitive behavior or self-dealing;
3. Prohibiting affiliated entities from engaging in discriminatory behavior towards nonaffiliated units; and
4. Establishing codes of conduct detailing permissible relations between functionally separate units.
D. Neither a covered entity nor an affiliate thereof may be a party to a covered transaction without the prior approval of the Commission. Any such person proposing to be a party to such transaction shall file an application with the Commission. The Commission shall approve or disapprove such transaction within sixty days after the filing of a completed application; however, the sixty-day period may be extended by Commission order for a period not to exceed an additional 120 days. The application shall be deemed approved if the Commission fails to act within such initial or extended period. The Commission shall approve such application if it finds, after notice and opportunity for hearing, that the transaction will comply with the requirements of subsection E, and may, as a part of its approval, establish such conditions or limitations on such transaction as it finds necessary to ensure compliance with subsection E.
E. A transaction described in subsection D shall not:
1. Substantially lessen competition among the actual or prospective providers of noncompetitive electric service or of a service which is, or is likely to become, a competitive electric service; or
2. Jeopardize or impair the safety or reliability of electric service in the Commonwealth, or the provision of any noncompetitive electric service at just and reasonable rates.
F. Except as provided in subdivision B 5, nothing in this chapter shall be deemed to abrogate or modify the Commission's authority under Chapter 3 (§ 56-55 et seq.), 4 (§ 56-76 et seq.) or 5 (§ 56-88 et seq.) of this title. However, any person subject to the requirements of subsection D that is also subject to the requirements of Chapter 5 of this title may be exempted from compliance with the requirements of Chapter 5 of this title.
1999, c. 411; 2000, c. 991; 2001, c. 748; 2007, cc. 888, 933.
Nothing in this chapter shall be construed to exempt or immunize from punishment or prosecution, conduct violative of federal antitrust laws, or the antitrust laws of this Commonwealth.
1999, c. 411.
A. The Commission shall develop an electric energy consumer education program designed to provide the following information to retail customers:
1. Information regarding energy conservation, energy efficiency, demand-side management, demand response, and renewable energy;
2. Information concerning demand-side management and demand response programs offered in the Commonwealth to retail customers;
3. Information regarding the matters described in subdivisions 1 and 2 that are specifically designed for the industrial, commercial, residential, and government sectors; and
4. Such other information as the Commission may deem necessary and appropriate in the public interest.
B. The Commission shall complete the development of the consumer education program described in subsection A, and report its findings and recommendations to the Commission on Electric Utility Regulation as frequently as may be required by such Commission concerning:
1. The scope of such recommended program consistent with the requirements of subsection A;
2. Materials and media required to effectuate any such program;
3. State agency and nongovernmental entity participation;
4. Program duration;
5. Funding requirements and mechanisms for any such program; and
6. Such other findings and recommendations the Commission deems appropriate in the public interest.
C. The Commission shall develop regulations governing marketing practices by public service companies, licensed suppliers, aggregators or any other providers of services made competitive by this chapter, including regulations to prevent unauthorized switching of suppliers, unauthorized charges, and improper solicitation activities. The Commission shall also establish standards for marketing information to be furnished by licensed suppliers, aggregators or any other providers of services made competitive by this chapter, which information shall include standards concerning:
1. Pricing and other key contract terms and conditions;
2. To the extent feasible, fuel mix and emissions data on at least an annualized basis;
3. Customer's rights of cancellation following execution of any contract;
4. Toll-free telephone number for customer assistance; and
5. Such other and further marketing information as the Commission may deem necessary and appropriate in the public interest.
D. The Commission shall also establish standards for billing information to be furnished by public service companies, suppliers, aggregators or any other providers of services made competitive by this chapter. Such billing information standards shall require that billing formation:
1. Distinguishes between charges for regulated services and unregulated services;
2. Is presented in a format that complies with standards to be established by the Commission;
3. Discloses, to the extent feasible, fuel mix and emissions data on at least an annualized basis; and
4. Includes such other billing information as the Commission deems necessary and appropriate in the public interest.
E. The Commission shall establish or maintain a complaint bureau for the purpose of receiving, reviewing and investigating complaints by retail customers against public service companies, licensed suppliers, aggregators and other providers of any services made competitive under this chapter. Upon the request of any interested person or the Attorney General, or upon its own motion, the Commission shall be authorized to inquire into possible violations of this chapter and to enjoin or punish any violations thereof pursuant to its authority under this chapter, this title, and under Title 12.1. The Attorney General shall have a right to participate in such proceedings consistent with the Commission's Rules of Practice and Procedure.
F. The Commission shall establish reasonable limits on customer security deposits required by public service companies, suppliers, aggregators or any other persons providing competitive services pursuant to this chapter.
A. The Commission shall establish and implement the consumer education program developed pursuant to subsection A of § 56-592. In establishing such a program, the Commission shall take into account the findings and recommendations of the subgroup on Information/Consumer Education that was established in conjunction with the Commission's proceeding in Case PUE-2007-00049, that implemented the third enactment of Chapters 888 and 933 of the Acts of Assembly of 2007.
B. The program shall be designed to (i) enable consumers to make rational and informed choices about the matters described in subsection A of § 56-592, including but not limited to demand side management, energy conservation, and energy efficiency, (ii) help consumers reduce transaction costs in making decisions regarding such matters, and (iii) foster compliance with the consumer protection provisions of this chapter.
C. The Commission shall regularly consult with representatives of consumer organizations, community-based groups, state agencies, incumbent utilities, and other interested parties throughout the program's implementation and operation.
D. Pursuant to the provisions of § 30-205, the Commission shall provide periodic updates to the Commission on Electric Utility Regulation concerning the program's implementation and operation.
E. The Commission shall fund the establishment and operation of such consumer education program through the special regulatory revenue tax currently authorized by § 58.1-2660 and the special regulatory tax authorized by Chapter 29 (§ 58.1-2900 et seq.) of Title 58.1.
A. No entity subject to this chapter shall use any deception, fraud, false pretense, misrepresentation, or any deceptive or unfair practices in providing, distributing or marketing electric service.
B. 1. Any person who suffers loss (i) as the result of marketing practices, including telemarketing practices, engaged in by any public service company, licensed supplier, aggregator or any other provider of any service made competitive under this chapter, and in violation of subsection C of § 56-592, including any rule or regulation adopted by the Commission pursuant thereto, or (ii) as the result of any violation of subsection A, shall be entitled to initiate an action to recover actual damages, or $500, whichever is greater. If the trier of fact finds that the violation was willful, it may increase damages to an amount not exceeding three times the actual damages sustained, or $1,000, whichever is greater.
2. Upon referral from the Commission, the Attorney General, the attorney for the Commonwealth, or the attorney for any city, county, or town may cause an action to be brought in the appropriate circuit court for relief of violations within the scope of (i) subsection C of § 56-592, including any rule or regulation adopted by the Commission pursuant thereto or (ii) subsection A.
C. Notwithstanding any other provision of law to the contrary, in addition to any damages awarded, such person, or any governmental agency initiating such action, also may be awarded reasonable attorney's fees and court costs.
D. Any action pursuant to this section shall be commenced within two years after its accrual. The cause of action shall accrue as provided in § 8.01-230. However, if the Commission initiates proceedings, or any other governmental agency files suit for the purpose of enforcing subsection A of this section or the provisions of subsection C of § 56-592, the time during which such proceeding or governmental suit and all appeals therefrom is pending shall not be counted as any part of the period within which an action under this section shall be brought.
E. The circuit court may make such additional orders or decrees as may be necessary to restore to any identifiable person any money or property, real, personal, or mixed, tangible or intangible, which may have been acquired from such person by means of any act or practice violative of subsection A of this section or subsection C of § 56-592, provided, that such person shall be identified by order of the court within 180 days from the date of any order permanently enjoining the unlawful act or practice.
F. In any case arising under this section, no liability shall be imposed upon any licensed supplier, aggregator or any other provider of any service made competitive under this chapter, who shows by a preponderance of the evidence that (i) the act or practice alleged to be in violation of subsection A of this section or subsection C of § 56-592 was an act or practice over which the same had no control or (ii) the alleged violation resulted from a bona fide error notwithstanding the maintenance of procedures reasonably adopted to avoid a violation. However, nothing in this section shall prevent the court from ordering restitution and payment of reasonable attorney's fees and court costs pursuant to subsection C to individuals aggrieved as a result of an unintentional violation of subsection A of this section or subsection C of § 56-592.
A. The Commission shall establish by regulation a program that affords eligible customer-generators the opportunity to participate in net energy metering, and a program, to begin no later than July 1, 2014, for customers of investor-owned utilities and to begin no later than July 1, 2015, and to end July 1, 2019, for customers of electric cooperatives as provided in subsection G, to afford eligible agricultural customer-generators the opportunity to participate in net energy metering. The regulations may include, but need not be limited to, requirements for (i) retail sellers; (ii) owners or operators of distribution or transmission facilities; (iii) providers of default service; (iv) eligible customer-generators; (v) eligible agricultural customer-generators; or (vi) any combination of the foregoing, as the Commission determines will facilitate the provision of net energy metering, provided that the Commission determines that such requirements do not adversely affect the public interest. On and after July 1, 2017, small agricultural generators or eligible agricultural customer-generators may elect to interconnect pursuant to the provisions of this section or as small agricultural generators pursuant to § 56-594.2, but not both. Existing eligible agricultural customer-generators may elect to become small agricultural generators, but may not revert to being eligible agricultural customer-generators after such election. On and after July 1, 2019, interconnection of eligible agricultural customer-generators shall cease for electric cooperatives only, and such facilities shall interconnect solely as small agricultural generators. For electric cooperatives, eligible agricultural customer-generators whose renewable energy generating facilities were interconnected before July 1, 2019, may continue to participate in net energy metering pursuant to this section for a period not to exceed 25 years from the date of their renewable energy generating facility's original interconnection.
B. For the purpose of this section:
"Eligible agricultural customer-generator" means a customer that operates a renewable energy generating facility as part of an agricultural business, which generating facility (i) uses as its sole energy source solar power, wind power, or aerobic or anaerobic digester gas, (ii) does not have an aggregate generation capacity of more than 500 kilowatts, (iii) is located on land owned or controlled by the agricultural business, (iv) is connected to the customer's wiring on the customer's side of its interconnection with the distributor; (v) is interconnected and operated in parallel with an electric company's transmission and distribution facilities, and (vi) is used primarily to provide energy to metered accounts of the agricultural business. An eligible agricultural customer-generator may be served by multiple meters serving the eligible agricultural customer-generator that are located at the same or adjacent sites, such that the eligible agricultural customer-generator may aggregate in a single account the electricity consumption and generation measured by the meters, provided that the same utility serves all such meters. The aggregated load shall be served under the appropriate tariff.
"Eligible customer-generator" means a customer that owns and operates, or contracts with other persons to own, operate, or both, an electrical generating facility, including any additions or enhancements such as battery storage or a smart inverter, that (i) has a capacity of not more than 25 kilowatts for residential customers and not more than three megawatts for nonresidential customers; (ii) uses as its total source of fuel renewable energy, as defined in § 56-576; (iii) is located on land owned or leased by the customer and is connected to the customer's wiring on the customer's side of its interconnection with the distributor; (iv) is interconnected and operated in parallel with an electric company's transmission and distribution facilities; and (v) is intended primarily to offset all or part of the customer's own electricity requirements. No contract, lease, or arrangement by which a third party owns, maintains, or operates an electrical generating facility on an eligible customer-generator's property shall constitute the sale of electricity or cause the customer-generator or the third party to be considered an electric utility by virtue of participating in net energy metering. In addition to the electrical generating facility size limitations in clause (i), the capacity of any generating facility installed under this section between July 1, 2015, and July 1, 2020, shall not exceed the expected annual energy consumption based on the previous 12 months of billing history or an annualized calculation of billing history if 12 months of billing history is not available. In addition to the electrical generating facility size limitation in clause (i), in the certificated service territory of a Phase I Utility, the capacity of any generating facility installed under this section after July 1, 2020, shall not exceed 100 percent of the expected annual energy consumption based on the previous 12 months of billing history or an annualized calculation of billing history if 12 months of billing history is not available, and in the certificated service territory of a Phase II Utility, the capacity of any generating facility installed under this section after July 1, 2020, shall not exceed 150 percent of the expected annual energy consumption based on the previous 12 months of billing history or an annualized calculation of billing history if 12 months of billing history is not available.
"Net energy metering" means measuring the difference, over the net metering period, between (i) electricity supplied to an eligible customer-generator or eligible agricultural customer-generator from the electric grid and (ii) the electricity generated and fed back to the electric grid by the eligible customer-generator or eligible agricultural customer-generator.
"Net metering period" means the 12-month period following the date of final interconnection of the eligible customer-generator's or eligible agricultural customer-generator's system with an electric service provider, and each 12-month period thereafter.
"Small agricultural generator" has the same meaning that is ascribed to that term in § 56-594.2.
C. The Commission's regulations shall ensure that (i) the metering equipment installed for net metering shall be capable of measuring the flow of electricity in two directions and (ii) any eligible customer-generator seeking to participate in net energy metering shall notify its supplier and receive approval to interconnect prior to installation of an electrical generating facility. The electric distribution company shall have 30 days from the date of notification for residential facilities, and 60 days from the date of notification for nonresidential facilities, to determine whether the interconnection requirements have been met. Such regulations shall allocate fairly the cost of such equipment and any necessary interconnection. An eligible customer-generator's electrical generating system, and each electrical generating system of an eligible agricultural customer-generator, shall meet all applicable safety and performance standards established by the National Electrical Code, the Institute of Electrical and Electronics Engineers, and accredited testing laboratories such as Underwriters Laboratories. Beyond the requirements set forth in this section and to ensure public safety, power quality, and reliability of the supplier's electric distribution system, an eligible customer-generator or eligible agricultural customer-generator whose electrical generating system meets those standards and rules shall bear all reasonable costs of equipment required for the interconnection to the supplier's electric distribution system, including costs, if any, to (a) install additional controls and (b) perform or pay for additional tests. No eligible customer-generator or eligible agricultural customer-generator shall be required to provide proof of liability insurance or to purchase additional liability insurance as a condition of interconnection.
D. The Commission shall establish minimum requirements for contracts to be entered into by the parties to net metering arrangements. Such requirements shall protect the eligible customer-generator or eligible agricultural customer-generator against discrimination by virtue of its status as an eligible customer-generator or eligible agricultural customer-generator, and permit customers that are served on time-of-use tariffs that have electricity supply demand charges contained within the electricity supply portion of the time-of-use tariffs to participate as an eligible customer-generator or eligible agricultural customer-generator. Notwithstanding the cost allocation provisions of subsection C, eligible customer-generators or eligible agricultural customer-generators served on demand charge-based time-of-use tariffs shall bear the incremental metering costs required to net meter such customers.
E. If electricity generated by an eligible customer-generator or eligible agricultural customer-generator over the net metering period exceeds the electricity consumed by the eligible customer-generator or eligible agricultural customer-generator, the customer-generator or eligible agricultural customer-generator shall be compensated for the excess electricity if the entity contracting to receive such electric energy and the eligible customer-generator or eligible agricultural customer-generator enter into a power purchase agreement for such excess electricity. Upon the written request of the eligible customer-generator or eligible agricultural customer-generator, the supplier that serves the eligible customer-generator or eligible agricultural customer-generator shall enter into a power purchase agreement with the requesting eligible customer-generator or eligible agricultural customer-generator that is consistent with the minimum requirements for contracts established by the Commission pursuant to subsection D. The power purchase agreement shall obligate the supplier to purchase such excess electricity at the rate that is provided for such purchases in a net metering standard contract or tariff approved by the Commission, unless the parties agree to a higher rate. The eligible customer-generator or eligible agricultural customer-generator owns any renewable energy certificates associated with its electrical generating facility; however, at the time that the eligible customer-generator or eligible agricultural customer-generator enters into a power purchase agreement with its supplier, the eligible customer-generator or eligible agricultural customer-generator shall have a one-time option to sell the renewable energy certificates associated with such electrical generating facility to its supplier and be compensated at an amount that is established by the Commission to reflect the value of such renewable energy certificates. Nothing in this section shall prevent the eligible customer-generator or eligible agricultural customer-generator and the supplier from voluntarily entering into an agreement for the sale and purchase of excess electricity or renewable energy certificates at mutually-agreed upon prices if the eligible customer-generator or eligible agricultural customer-generator does not exercise its option to sell its renewable energy certificates to its supplier at Commission-approved prices at the time that the eligible customer-generator or eligible agricultural customer-generator enters into a power purchase agreement with its supplier. All costs incurred by the supplier to purchase excess electricity and renewable energy certificates from eligible customer-generators or eligible agricultural customer-generators shall be recoverable through its Renewable Energy Portfolio Standard (RPS) rate adjustment clause, if the supplier has a Commission-approved RPS plan. If not, then all costs shall be recoverable through the supplier's fuel adjustment clause. For purposes of this section, "all costs" shall be defined as the rates paid to the eligible customer-generator or eligible agricultural customer-generator for the purchase of excess electricity and renewable energy certificates and any administrative costs incurred to manage the eligible customer-generator's or eligible agricultural customer-generator's power purchase arrangements. The net metering standard contract or tariff shall be available to eligible customer-generators or eligible agricultural customer-generators on a first-come, first-served basis in each electric distribution company's Virginia service area until the rated generating capacity owned and operated by eligible customer-generators, eligible agricultural customer-generators, and small agricultural generators in the Commonwealth reaches six percent, in the aggregate, five percent of which is available to all customers and one percent of which is available only to low-income utility customers of each electric distribution company's adjusted Virginia peak-load forecast for the previous year, and shall require the supplier to pay the eligible customer-generator or eligible agricultural customer-generator for such excess electricity in a timely manner at a rate to be established by the Commission.
On and after the earlier of (i) 2024 for a Phase I Utility or 2025 for a Phase II Utility or (ii) when the aggregate rated generating capacity owned and operated by eligible customer-generators, eligible agricultural customer-generators, and small agricultural generators in the Commonwealth reaches three percent of a Phase I or Phase II Utility's adjusted Virginia peak-load forecast for the previous year, the Commission shall conduct a net energy metering proceeding.
In any net energy metering proceeding, the Commission shall, after notice and opportunity for hearing, evaluate and establish (a) an amount customers shall pay on their utility bills each month for the costs of using the utility's infrastructure; (b) an amount the utility shall pay to appropriately compensate the customer, as determined by the Commission, for the total benefits such facilities provide; (c) the direct and indirect economic impact of net metering to the Commonwealth; and (d) any other information the Commission deems relevant. The Commission shall establish an appropriate rate structure related thereto, which shall govern compensation related to all eligible customer-generators, eligible agricultural customer-generators, and small agricultural generators, except low-income utility customers, that interconnect after the effective date established in the Commission's final order. Nothing in the Commission's final order shall affect any eligible customer-generators, eligible agricultural customer-generators, and small agricultural generators who interconnect before the effective date of such final order. As part of the net energy metering proceeding, the Commission shall evaluate the six percent aggregate net metering cap and may, if appropriate, raise or remove such cap. The Commission shall enter its final order in such a proceeding no later than 12 months after it commences such proceeding, and such final order shall establish a date by which the new terms and conditions shall apply for interconnection and shall also provide that, if the terms and conditions of compensation in the final order differ from the terms and conditions available to customers before the proceeding, low-income utility customers may interconnect under whichever terms are most favorable to them.
F. Any residential eligible customer-generator or eligible agricultural customer-generator, in the service territory of a Phase II Utility who owns and operates, or contracts with other persons to own, operate, or both, an electrical generating facility with a capacity that exceeds 15 kilowatts shall pay to its supplier, in addition to any other charges authorized by law, a monthly standby charge. The amount of the standby charge and the terms and conditions under which it is assessed shall be in accordance with a methodology developed by the supplier and approved by the Commission. The Commission shall approve a supplier's proposed standby charge methodology if it finds that the standby charges collected from all such eligible customer-generators and eligible agricultural customer-generators allow the supplier to recover only the portion of the supplier's infrastructure costs that are properly associated with serving such eligible customer-generators or eligible agricultural customer-generators. Such an eligible customer-generator or eligible agricultural customer-generator shall not be liable for a standby charge until the date specified in an order of the Commission approving its supplier's methodology. For customers of all other investor-owned utilities, on and after July 1, 2020, standby charges are prohibited for any residential eligible customer-generator or agricultural customer-generator.
G. On and after the later of July 1, 2019, or the effective date of regulations that the Commission is required to adopt pursuant to § 56-594.01, (i) net energy metering in the service territory of each electric cooperative shall be conducted as provided in a program implemented pursuant to § 56-594.01 and (ii) the provisions of this section shall not apply to net energy metering in the service territory of an electric cooperative except as provided in § 56-594.01.
H. The Commission may adopt such rules or establish such guidelines as may be necessary for its general administration of this section.
I. When the Commission conducts a net energy metering proceeding, it shall:
1. Investigate and determine the costs and benefits of the current net energy metering program;
2. Establish an appropriate netting measurement interval for a successor tariff that is just and reasonable in light of the costs and benefits of the net metering program in aggregate, and applicable to new requests for net energy metering service;
3. Determine a specific avoided cost for customer-generators, the different type of customer-generator technologies where the Commission deems it appropriate, and establish the methodology for determining the compensation rate for any net excess generation determined according to the applicable net measurement interval for any new tariff; and
4. Make all reasonable efforts to ensure that the net energy metering program does not result in unreasonable cost-shifting to nonparticipating electric utility customers.
J. In evaluating the costs and benefits of the net energy metering program, the Commission shall consider:
1. The aggregate impact of customer-generators on the electric utility's long-run marginal costs of generation, distribution, and transmission;
2. The cost of service implications of customer-generators on other customers within the same class, including an evaluation of whether customer-generators provide an adequate rate of return to the electrical utility compared to the otherwise applicable rate class when, for analytical purposes only, examined as a separate class within a cost of service study;
3. The direct and indirect economic impact of the net energy metering program to the Commonwealth; and
4. Any other information it deems relevant, including environmental and resilience benefits of customer-generator facilities.
K. Notwithstanding the provisions of this section, § 56-585.1:8, or any other provision of law to the contrary, any locality that is a nonjurisdictional customer of a Phase II Utility, as defined in § 56-585.1:3, and is in Planning District Eight with a population greater than 1 million may (i) install solar-powered or wind-powered electric generation facilities with a rated capacity not exceeding five megawatts, whether the facilities are owned by the locality or owned and operated by a third party pursuant to a contract with the locality, on any locality-owned site within the locality and (ii) credit the electricity generated at any such facility as directed by the governing body of the locality to any one or more of the metered accounts of buildings or other facilities of the locality or the locality's public school division that are located within the locality, without regard to whether the buildings and facilities are located at the same site where the electric generation facility is located or at a site contiguous thereto. The amount of the credit for such electricity to the metered accounts of the locality or its public school division shall be identical, with respect to the rate structure, all retail rate components, and monthly charges, to the amount the locality or public school division would otherwise be charged for such amount of electricity under its contract with the public utility, without the assessment by the public utility of any distribution charges, service charges, or fees in connection with or arising out of such crediting.
L. Any eligible customer-generator or eligible agricultural customer-generator may participate in demand response, energy efficiency, or peak reduction from dispatch of onsite battery service, provided that the compensation received is in exchange for a distinct service that is not already compensated by net metering credits for electricity exported to the electric distribution system or compensated by any other utility program or tariff. The Commission shall review and evaluate the continuing need for the imposition of standby or other charges on eligible customer-generators or eligible agricultural customer-generators in any net energy metering proceeding conducted pursuant to subsection E.
1999, c. 411; 2004, c. 827; 2006, c. 470; 2007, cc. 877, 888, 933; 2009, c. 804; 2011, c. 239; 2013, c. 268; 2015, cc. 431, 432; 2017, cc. 565, 581; 2019, cc. 742, 763; 2020, cc. 1187, 1188, 1189, 1193, 1194, 1239; 2024, cc. 783, 827.
A. The Commission shall establish by regulation a program that affords eligible customer-generators the opportunity to participate in net energy metering in the service territory of each electric cooperative, which program shall commence on the later of July 1, 2019, or the effective date of such regulations. Such regulations shall be similar to existing regulations promulgated pursuant to § 56-594. In lieu of adopting new regulations, the Commission may amend such existing regulations to apply to electric cooperatives with such revisions as are required to comply with the provisions of this section. The regulations may include requirements applicable to (i) retail sellers, (ii) owners or operators of distribution or transmission facilities, (iii) providers of default service, (iv) eligible customer-generators, or (v) any combination of the foregoing, as the Commission determines will facilitate the provision of net energy metering, provided that the Commission determines that such requirements do not adversely affect the public interest.
B. As used in this section:
"Eligible customer-generator" means a customer that owns and operates, or contracts with other persons to own, operate, or both, an electrical generating facility that (i) has a capacity of not more than 20 kilowatts for residential customers and not more than one megawatt for nonresidential customers on an electrical generating facility placed in service after July 1, 2015; (ii) uses as its total source of fuel renewable energy as defined in § 56-576; (iii) is located on the customer's premises and is connected to the customer's wiring on the customer's side of its interconnection with the distributor; (iv) is interconnected and operated in parallel with an electric company's transmission and distribution facilities; and (v) is intended primarily to offset all or part of the customer's own electricity requirements. In addition to the electrical generating facility size limitations in clause (i), the capacity of any generating facility installed under this section after July 1, 2015, shall not exceed the expected annual energy consumption based on the previous 12 months of billing history or an annualized calculation of billing history if 12 months of billing history is not available.
"Net energy metering" means measuring the difference, over the net metering period, between (i) electricity supplied to an eligible customer-generator from the electric grid and (ii) the electricity generated and fed back to the electric grid by the eligible customer-generator.
"Net metering period" means the 12-month period following the date of final interconnection of the eligible customer-generator's system with an electric service provider, and each 12-month period thereafter.
C. The Commission's regulations shall ensure that (i) the metering equipment installed for net metering shall be capable of measuring the flow of electricity in two directions and (ii) any eligible customer-generator seeking to participate in net energy metering shall notify its supplier and receive approval to interconnect prior to installation of an electrical generating facility. The Commission shall publish a form for such prior notice and such notice shall be processed promptly by the supplier prior to any construction activity taking place. After construction, inspection and documentation thereof shall be required prior to interconnection. The electric distribution company shall have 30 days from the date of each notification for residential facilities, and 60 days from the date of each notification for nonresidential facilities, to determine whether the interconnection requirements have been met. Such regulations shall allocate fairly the cost of such equipment and any necessary interconnection. An eligible customer-generator's electrical generating system shall meet all applicable safety and performance standards established by the National Electrical Code, the Institute of Electrical and Electronics Engineers, and accredited testing laboratories such as Underwriters Laboratories. In addition to the requirements set forth in this section and to ensure public safety, power quality, and reliability of the supplier's electric distribution system, an eligible customer-generator whose electrical generating system meets those standards and rules shall bear all reasonable costs of equipment required for the interconnection to the supplier's electric distribution system, including costs, if any, to (a) install additional controls, (b) perform or pay for additional tests, and (c) purchase additional liability insurance. An electric cooperative may publish and use its own forms, including an electronic form, for purposes of implementing the regulations described herein so long as the information collected on the Commission's form is also collected by the cooperative and submitted to the Commission.
D. The Commission shall establish minimum requirements for contracts to be entered into by the parties to net metering arrangements. Such requirements shall protect the eligible customer-generator against discrimination by virtue of its status as an eligible customer-generator and permit customers that are served on time-of-use tariffs that have electricity supply demand charges contained within the electricity supply portion of the time-of-use tariffs to participate as an eligible customer-generator. Notwithstanding the cost allocation provisions of subsection C, eligible customer-generators served on demand charge-based time-of-use tariffs shall bear the incremental metering costs required to net meter such customers.
E. If electricity generated by an eligible customer-generator over the net metering period exceeds the electricity consumed by the eligible customer-generator, the customer-generator shall be compensated for the excess electricity if the entity contracting to receive such electric energy and the eligible customer-generator enter into a power purchase agreement for such excess electricity. Upon the written request of the eligible customer-generator, the supplier that serves the eligible customer-generator shall enter into a power purchase agreement with the requesting eligible customer-generator that is consistent with the minimum requirements for contracts established by the Commission pursuant to subsection D. The power purchase agreement shall obligate the supplier to purchase such excess electricity at the rate that is provided for such purchases in a net metering standard contract or tariff approved by the Commission, unless the parties agree to a higher rate. The eligible customer-generator owns any renewable energy certificates associated with its electrical generating facility; however, at the time that the eligible customer-generator enters into a power purchase agreement with its supplier, the eligible customer-generator shall have a one-time option to sell the renewable energy certificates associated with such electrical generating facility to its supplier and be compensated at an amount that is established by the Commission to reflect the value of such renewable energy certificates. Nothing in this section shall prevent the eligible customer-generator and the supplier from voluntarily entering into an agreement for the sale and purchase of excess electricity or renewable energy certificates at mutually agreed upon prices if the eligible customer-generator does not exercise its option to sell its renewable energy certificates to its supplier at Commission-approved prices at the time that the eligible customer-generator enters into a power purchase agreement with its supplier. All costs incurred by the supplier to purchase excess electricity and renewable energy certificates from eligible customer-generators shall be recoverable through its fuel adjustment clause. For purposes of this section, "all costs" shall be defined as the rates paid to the eligible customer-generator for the purchase of excess electricity and renewable energy certificates and any administrative costs incurred to manage the eligible customer-generator's power purchase arrangements. The net metering standard contract or tariff shall be available to eligible customer-generators on a first-come, first-served basis, subject to the provisions of subsection F, and shall require the supplier to pay the eligible customer-generator for such excess electricity in a timely manner at a rate to be established by the Commission.
F. Net energy metering shall be open to customers on a first-come, first-served basis until such time as the total capacity of the generation facilities, expressed in alternating current nameplate, reaches two percent of system peak for residential customers, two percent of system peak for not-for-profit and nonjurisdictional customers, and one percent of system peak for other nonresidential customers, which are herein referred to as the electric cooperative's caps. As used in this subsection, "percent of system peak" refers to a percentage of the electric cooperative's highest total system peak, based on the noncoincident peak of the electric cooperative or the coincident peak of all of the electric cooperative's customers, within the past three years as listed in Part O, Line 20 of Form 7 filed with the Rural Utilities Service or its equivalent, less any portion of the cooperative's total load that is served by a competitive service provider or by a market-based rate. Such caps shall not decrease but may increase if the system peak in any year exceeds the previous year's system peak. Nothing in this subsection shall amend or confer new rights upon any existing nonjurisdictional contract or arrangement or work to submit any nonjurisdictional customer, contract, or arrangement to the jurisdiction of the Commission. For purposes of calculating the caps established in this subsection, all net energy metering shall be counted, whenever interconnected, and shall include net energy metering interconnected pursuant to § 56-594, agricultural net energy metering, and any net energy metering entered into with a third-party provider registered pursuant to subsection K. Net energy metering with nonjurisdictional customers entered into prior to July 1, 2019, may be counted toward the caps, in the discretion of the cooperative, as net energy metering if the nonjurisdictional customer takes service pursuant to a cooperative's net energy metering rider. Net energy metering with nonjurisdictional customers entered into on or after July 1, 2019, shall be counted toward the caps by default unless the cooperative has reason to exclude such net energy metering as subject to a separate contract or arrangement. Each electric cooperative governed by this section shall publish information regarding the calculation and status of its caps pursuant to this subsection, or the electric cooperative's systemwide cap established in § 56-585.4 if applicable, on the electric cooperative's website.
G. An electric cooperative may, without Commission approval or the requirement of any filing other than as provided in this subsection, upon the adoption by its board of directors of a resolution so providing, raise the caps established in subsection F, with any increase allocated among residential, not-for-profit and nonjurisdictional, and other nonresidential customers as the board of directors may find to be in the interests of the electric cooperative's membership. The electric cooperative shall promptly file a revised net energy metering compliance filing with the Commission for informational purposes.
H. Any residential eligible customer-generator who owns and operates, or contracts with other persons to own, operate, or both, an electrical generating facility with a capacity that exceeds 10 kilowatts shall pay to its supplier, in addition to any other charges authorized by law, a monthly standby charge. The amount of the standby charge and the terms and conditions under which it is assessed shall be in accordance with a methodology developed by the supplier and approved by the Commission. The Commission shall approve a supplier's proposed standby charge methodology if it finds that the standby charges collected from all such eligible customer-generators allow the supplier to recover only the portion of the supplier's infrastructure costs that are properly associated with serving such eligible customer-generators. Such an eligible customer-generator shall not be liable for a standby charge until the date specified in an order of the Commission approving its supplier's methodology.
I. Any eligible agricultural customer-generator interconnected in an electric cooperative service territory prior to July 1, 2019, shall continue to be governed by § 56-594 and the regulations adopted pursuant thereto throughout the grandfathering period described in subsection A of § 56-594.
J. Any eligible customer-generator served by a competitive service provider pursuant to the provisions of § 56-577 shall engage in net energy metering only with such supplier and pursuant only to tariffs filed by such supplier. Such an eligible customer-generator shall pay the full portion of its distribution charges, without offset or netting, to its electric cooperative.
K. After the conclusion of the Commission's rulemaking proceeding pursuant to subsection L, third-party partial requirements power purchase agreements, the purpose of which is to finance the purchase of renewable generation facilities by eligible customer-generators through the sale of electricity, shall be permitted pursuant to the provisions of this section only for those retail customers and nonjurisdictional customers of the electric cooperative that are exempt from federal income taxation, unless otherwise permitted by § 56-585.4 or subsection M. No person shall offer a third-party partial requirements power purchase agreement in the service territory of an electric cooperative without fulfilling the registration requirements set forth in this section and complying with applicable Commission rules, including those adopted pursuant to subdivision L 2.
L. After August 1, 2019, but before January 1, 2020, the Commission shall initiate a rulemaking proceeding to promulgate the regulations necessary to implement this section as follows:
1. In conducting such a proceeding, the Commission may require notice to be given to current eligible customer-generators and eligible agricultural customer-generators but shall not require general publication of the notice. An opportunity to request a hearing shall be afforded, but a hearing is not required. In the rulemaking proceeding, the electric cooperatives governed by this section shall be required to submit compliance filings, but no other individual proceedings shall be required or conducted.
2. In promulgating regulations to govern third-party power purchase agreement providers as retail sellers, the Commission shall:
a. Direct the staff to administer a registration system for such providers;
b. Enumerate in its regulations the jurisdiction of the Commission over providers, generally limited in scope to the behavior of providers, customer complaints, and their compliance with the registration requirements and stating clearly that civil contract disputes and claims for damages against providers shall not be subject to the jurisdiction of the Commission;
c. Enumerate in its regulations the maximum extent of its authority over the providers, to be limited to any or all of:
(1) Monetary penalties against registered providers not to exceed $30,000 per provider registration;
(2) Orders for providers to cease or desist from a certain practice, act, or omission;
(3) Debarment of registered providers;
(4) The issuance of orders to show cause; and
(5) Authority incident to subdivisions (1) through (4);
d. Delineate in its regulations two classes of providers, one for residential customers and one for nonresidential customers;
e. Direct the staff to set up a self-certification system as described in this subdivision;
f. Establish business practice and consumer protection standards from a national renewable energy association whose business is germane to the businesses of the providers;
g. Require providers to comply with other applicable Commission regulations governing interconnection and safety, including utility procedures governing the same;
h. Require minimum capitalization or other bond or surety that, in the judgment of the Commission, is necessary for adequate consumer protection and in the public interest;
i. Require the payment of a fee of $250 for residential and nonresidential provider registration; and
j. Provide that no registered provider, by virtue of that status alone, shall be considered a public utility or competitive service provider for purposes of this title.
3. The self-certification system described in this subdivision shall require a provider to affirm to the staff, under the penalty of revocation of registration, (i) that it is licensed to do business in Virginia; (ii) the names of the responsible officers of the provider entity; (iii) that its named officers have no felony convictions or convictions for crimes of moral turpitude; (iv) that it will abide by all applicable Commission regulations promulgated under this section or for purposes of interconnections and safety; (v) that it will appoint an officer to be a primary liaison to the staff; (vi) that it will appoint an employee to be a primary contact for customer complaints; (vii) that it will have and disclose to customers a dispute resolution procedure; (viii) that it has specified in its registration materials in which territories it intends to offer power purchase agreements; (ix) that it, and each of its named officers, agree to submit themselves to the jurisdiction of the Commission as described in this subdivision; and (x) that, once registered, the provider shall report any material changes in its registration materials to the staff, as a continuing obligation of registration. The staff shall send a copy of the registration materials to each cooperative in whose territory the provider intends to offer power purchase agreements. The staff, once satisfied that the certifications required pursuant to this subdivision are complete, and not more than 30 days following the initial and complete submittal of the registration materials, shall enter the provider onto the official register of providers. No formal Commission proceeding is required for registration but may be initiated if the staff (a) has reason to doubt the veracity of the certifications of the provider or (b) in any other case, if, in the judgment of the staff, extenuating or extraordinary circumstances exist that warrant a proceeding. The staff shall not investigate the corporate structure, financing, bookkeeping, accounting practices, contracting practices, prices, or terms and conditions in a third-party partial requirements power purchase agreement. Nothing in this section shall abridge the right of any person, including the Office of Attorney General, from proceeding in a cause of action under the Virginia Consumer Protection Act, § 59.1-196 et seq.
4. The Commission shall complete such rulemaking procedure within 12 months of its initiation.
M. An electric cooperative may, without approval of the Commission or the requirement of any filing other than as provided in this subsection, and upon the adoption by its board of directors of a resolution so providing, permit the use of any third-party partial requirements power purchase agreement, the purpose of which agreement is to finance the purchase of renewable generation facilities by eligible customer-generators through the sale of electricity for residential retail customers, nonresidential retail customers, or both. The electric cooperative shall promptly file a revised net energy metering compliance filing with the Commission for informational purposes.
A. For the purpose of this section:
"Electric cooperative" or "cooperative" means a utility formed under or subject to Chapter 9.1 (§ 56-231.15 et seq.) and subject to regulation as to rates and service by the Commission.
"Customer" means a customer interconnected to facilities of an electric cooperative pursuant to 20VAC5-314, generating or interconnected for export, which customer is neither selling power to the cooperative nor interconnected pursuant to § 56-594.01 or 56-594.2.
B. Any customer may enter into an agreement for local facilities usage charges, which may be denominated as an operations and maintenance agreement or facilities agreement or otherwise. Such agreement shall be deemed just and reasonable by operation of law without separate approval by the Commission.
C. In the absence of an agreement between the parties, an electric cooperative may apply at any time to the Commission for a tariff for local facilities usage charges for the use of cooperative system facilities. Local facilities usage charges shall be designed by the cooperative, either on the basis of line-miles of utility facilities used or the capacity of the interconnecting facility, or on the basis of a combination of these factors. The Commission shall approve a just and reasonable rate. In approving such rate, the Commission shall consider (i) the ongoing costs of operating and maintaining all local utility facilities used by interconnecting customers to access a contract path to PJM Interconnection, LLC, market delivery points, including a reasonable margin and all costs of any associated regulatory proceeding, and (ii) standard utility practices. The Commission is not required to conduct a hearing on any application pursuant to this subsection, but the Commission shall order notice to each affected customer and an opportunity to comment. Any party to the proceeding shall have the right to request a hearing on the application. Any proceeding conducted pursuant to this subsection shall be completed within 12 months of its commencement. Once the Commission approves a tariff for charges as described in this subsection, any interconnected customer shall be subject to the tariff thereafter. However, any agreements entered into pursuant to subsection B shall continue to have force and effect according to their terms and shall not be subject to the tariff unless the customer desires to transition to tariffed services.
D. In the absence of an agreement executed pursuant to subsection B or a specific tariff approved for local facilities usage charges pursuant to subsection C, any electric cooperative with a previously approved tariff for excess facilities charges may use such tariff to recover local facilities usage charges without seeking separate approval from the Commission. Any customer impacted by any action of a cooperative pursuant to this subsection shall have the right to petition the Commission for redress and review of the charges as applied to the customer by initiating a petition proceeding pursuant to subsection C of 5VAC5-20-100. The petitioner shall bear the burden of proof in such proceeding. If a cooperative's acts are found to be unjust or unreasonable, such a proceeding shall include the establishment of a tariff pursuant to subsection C. If such a proceeding includes the establishment of a tariff pursuant to subsection C, the cooperative shall bear the burden of proof. The results of any such proceeding shall not, in any case, invalidate an excess facilities tariff or charges as to any person other than the customer initiating the proceeding.
E. The provisions of this section shall be applied notwithstanding any other provision of law.
A. The Commission shall conduct pilot programs under which a person that owns or operates a solar-powered or wind-powered electricity generation facility located on premises owned or leased by an eligible customer-generator, as defined in § 56-594, shall be permitted to sell the electricity generated from such facility exclusively to such eligible customer-generator under a power purchase agreement used to provide third party financing of the costs of such a renewable generation facility (third party power purchase agreement), subject to the following terms, conditions, and restrictions:
1. Notwithstanding subsection G of § 56-580 or any other provision of law, a pilot program shall be conducted within the certificated service territory of each investor-owned electric utility ("Pilot Utility");
2. Except as provided in this subdivision, both jurisdictional and nonjurisdictional customers may participate in such pilot programs on a first-come, first-serve basis. The aggregated capacity of all generation facilities that are subject to such third party power purchase agreements at any time during the pilot program shall not exceed 500 megawatts for Virginia jurisdictional customers and 500 megawatts for Virginia nonjurisdictional customers. Such limitation on the aggregated capacity of such facilities shall constitute a portion of the existing limit of six percent of each Pilot Utility's adjusted Virginia peak-load forecast for the previous year that is available to eligible customer-generators pursuant to subsection E of § 56-594. Notwithstanding any provision of this section that incorporates provisions of § 56-594, the seller and the customer shall elect either to (i) enter into their third party power purchase agreement subject to the conditions and provisions of the Pilot Utility's net energy metering program under § 56-594 or (ii) provide that electricity generated from the generation facilities subject to the third party power purchase agreement will not be net metered under § 56-594, provided that an election not to net meter under § 56-594 shall not exempt the third party power purchase agreement and the parties thereto from the requirements of this section that incorporate provisions of § 56-594;
3. A solar-powered or wind-powered generation facility with a capacity of no less than 50 kilowatts and no more than three megawatts shall be eligible for a third party power purchase agreement under a pilot program; however, if the customer under such agreement is a low-income utility customer, as defined in § 56-576, or is an entity with tax-exempt status in accordance with § 501(c) of the Internal Revenue Code of 1954, as amended, then such facility is eligible for the pilot program even if it does not meet the 50 kilowatts minimum size requirement. The maximum generation capacity of three megawatts shall not affect the limits on the capacity of electrical generating capacities of 25 kilowatts for residential customers and three megawatts for nonresidential customers set forth in subsection B of § 56-594, which limitations shall continue to apply to net energy metering generation facilities regardless of whether they are the subject of a third party power purchase agreement under the pilot program;
4. A generation facility that is the subject of a third party power purchase agreement under the pilot program shall serve only one customer, and a third party power purchase agreement shall not serve multiple customers;
5. The customer under a third party power purchase agreement under the pilot program shall be subject to the interconnection and other requirements imposed on eligible customer-generators pursuant to subsection C of § 56-594, including the requirement that the customer bear the reasonable costs, as determined by the Commission, of the items described in clauses (a) and (b) of such subsection;
6. A third party power purchase agreement under the pilot program shall not be valid unless it conforms in all respects to the requirements of the pilot program conducted under the provisions of this section and unless the Commission and the Pilot Utility are provided written notice of the parties' intent to enter into a third party power purchase agreement not less than 30 days prior to the agreement's proposed effective date; and
7. An affiliate of the Pilot Utility shall be permitted to offer and enter into third party power purchase arrangements on the same basis as may any other person that satisfies the requirements of being a seller under a third party power purchase agreement under the pilot program.
B. The Commission shall review the pilot program established pursuant to subsection A in 2015 and every two years thereafter during the pilot program. In its review, the Commission shall determine whether the limitations in subdivisions A 2 and 3 should be expanded, reduced, or continued.
C. Any third party power purchase agreement that is not entered into pursuant to the pilot program established pursuant to subsection A is prohibited in the Pilot Utility's service territory, unless such third party power purchase agreement is entered into between a licensed supplier and a retail customer pursuant to § 56-577 where such supplier is responsible for serving 100 percent of the load requirements for each retail customer account it serves.
D. If the Commission approves a tariff proposed for electric power provided 100 percent from renewable energy that serves 100 percent of the load requirements for each retail customer account it serves under such tariff, hereafter referred to as a "green tariff," such a green tariff shall not be available to any party to a third party power purchase agreement for the account being served by such power purchase agreement, and such an agreement shall remain in effect notwithstanding the approval of the green tariff.
E. Nothing in this section shall be construed as (i) rendering any person, by virtue of its selling electric power to an eligible customer-generator under a third party power purchase agreement entered into pursuant to the pilot program established under this section, a public utility or a competitive service provider, (ii) imposing a requirement that such a person meet 100 percent of the load requirements for each retail customer account it serves, or (iii) affecting third party power purchase agreements in effect prior to July 1, 2013.
F. Nothing in this section shall abridge any rights of either party to an agreement between a Pilot Utility and a group purchasing organization acting on behalf of Virginia local governments regarding the purchase of electric service.
G. The Commission shall, by December 1, 2013, establish guidelines concerning (i) information to be provided in notices required under subdivision A 6 and (ii) procedures for aggregating and posting to the Commission's web site information derived from the aforesaid notices, including total capacity utilized by pilot projects for which notice has been received and capacity remaining available for future pilot projects. In addition, the Commission may adopt such rules or establish such guidelines as may be necessary for its general administration of the pilot program established under this section.
2013, cc. 358, 382; 2017, c. 803; 2020, cc. 1187, 1188, 1189, 1193, 1194, 1239; 2021, Sp. Sess. I, cc. 361, 362; 2024, cc. 783, 827.
A. As used in this section, "eligible farm" means an entity that owns or operates facilities within the Commonwealth for the generation of electric energy, which entity is described in subdivision (b)(10) of § 56-265.1.
B. Eligible farms shall be permitted to connect to the electrical grid in order to feed into the grid electricity generated by the eligible farm from its facilities that generate electricity from a waste-to-energy technology.
C. The Commission shall adopt regulations to implement this section pursuant to § 56-578.
2009, c. 746.
A. As used in this section:
"Small agricultural generating facility" means an electrical generating facility that:
1. Has a capacity:
a. Of not more than 1.5 megawatts; and
b. That does not exceed 150 percent of the customer's expected annual energy consumption based on the previous 12 months of billing history or an annualized calculation of billing history if 12 months of billing history is not available;
2. Uses as its total source of fuel renewable energy;
3. Is located on the customer's premises and is interconnected with its utility through a separate meter;
4. Is interconnected and operated in parallel with an electric utility's distribution but not transmission facilities;
5. Is designed so that the electricity generated by the facility is expected to remain on the utility's distribution system; and
6. Is a qualifying small power production facility pursuant to the Public Utility Regulatory Policies Act of 1978 (P.L. 95-617).
"Small agricultural generator" means a customer that:
1. Is not an eligible agricultural customer-generator pursuant to § 56-594;
2. Operates a small agricultural generating facility as part of (i) an agricultural business or (ii) any business granted a manufacturer license pursuant to subdivisions 1 through 6 of § 4.1-206.1;
3. May be served by multiple meters that are located at separate but contiguous sites;
4. May aggregate the electricity consumption measured by the meters, solely for purposes of calculating 150 percent of the customer's expected annual energy consumption, but not for billing or retail service purposes, provided that the same utility serves all of its meters;
5. Uses not more than 25 percent of contiguous land owned or controlled by the agricultural business for purposes of the renewable energy generating facility; and
6. Issues a certification under oath as to the amount of land being used for renewable generation.
"Utility" includes supplier or distributor, as applicable.
B. A small agricultural generator electing to interconnect pursuant to this section shall:
1. Enter into a power purchase agreement with its utility to sell all of the electricity generated from its small agricultural generating facility, which power purchase agreement obligates the utility to purchase all the electricity generated, at a rate agreed upon by the parties, but at a rate not less than the utility's Commission-approved avoided cost tariff for energy and capacity;
2. Have the rights described in subsection E of § 56-594 pertaining to an eligible agricultural customer-generator as to the renewable energy certificates or other environmental attributes generated by the renewable energy generating facility;
3. Abide by the appropriate small generator interconnection process as described in 20VAC5-314; and
4. Pay to its utility any necessary additional expenses as required by this section.
C. Utilities:
1. Shall purchase, through the power purchase agreement described in subdivision B 1, all of the output of the small agricultural generator;
2. Shall recover the cost for its distribution facilities to the generating meter either through a proportional cost-sharing agreement with the small agricultural generator or through metering the total capacity and energy placed on the distribution system by the small agricultural generator;
3. Shall recover all costs incurred by the utility to purchase electricity, capacity, and renewable energy certificates from the small agricultural generator:
a. If the utility has a Commission-approved Renewable Energy Portfolio Standard (RPS) plan and rate adjustment clause, through the utility's RPS rate adjustment clause; or
b. If the utility does not have a Commission-approved RPS rate adjustment clause, through the utility's fuel adjustment clause or through the utility's cost of purchased power;
4. May conduct settlement transactions for purchased power in dollars on the small agricultural generator's electric bill or through other means of settlement, in the utility's sole discretion;
5. Shall bill the small agricultural generator eligible costs for small generator interconnection studies required pursuant to the appropriate small generator interconnection process described in subdivision B 3; and
6. Shall bill its expenses, at cost, for any additional engineering studies that a small agricultural generator is required to pay prior to interconnection.
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, a 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. On an annual basis and pursuant to guidelines established by the Commission, the subscriber organization shall furnish to the utility allocation instructions for distributing excess bill credits to subscribers.
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 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, the Commission shall approve up to an additional 150 megawatts of capacity as part two of such program, 75 megawatts of which shall serve no more than 51 percent low-income customers. 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.
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. Within 180 days of finalization of the Commission's adoption of regulations for the shared solar program, a utility shall begin crediting subscriber accounts of each shared solar facility interconnected in its service territory, subject to the requirements of this section and regulations adopted thereto.
2020, cc. 1238, 1264; 2021, Sp. Sess. I, c. 532; 2024, cc. 715, 763.
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.
"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 I 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 the distribution system of an investor-owned electric utility 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.
"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 I Utility.
B. The Commission shall establish by regulation a program that affords customers of a Phase I Utility the opportunity to participate in shared solar projects. Under its shared solar program, a 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 percentage of shared solar capacity 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. On an annual basis and pursuant to guidelines established by the Commission, the subscriber organization shall furnish to the utility allocation instructions for distributing excess bill credits to subscribers.
7. Any renewable energy certificates associated with a shared solar facility shall be distributed to a Phase I Utility to be retired for compliance with such Phase I 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, (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.
E. The Commission shall approve a shared solar program of 50 megawatts or six percent of peak load, whichever is less.
F. The Commission shall establish by regulation a shared solar program that complies with the provisions of subsections B, C, D, and E by January 1, 2025, and shall require each utility to file any tariffs, agreements, or forms necessary for implementation of the program by July 1, 2025. 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. 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;
4. Not remove a customer from its otherwise applicable customer class in order to participate in a shared solar facility;
5. 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;
6. 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;
7. Adopt standardized consumer disclosure forms;
8. Allow the utility the opportunity to recover reasonable costs of administering the program;
9. Ensure nondiscriminatory and efficient requirements and utility procedures for interconnecting projects;
10. Allow for 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;
11. Include a program implementation schedule;
12. Prohibit credit checks as a means of establishing eligibility for residential customers to become subscribers;
13. Require a customer's affirmative consent by written or electronic signature before providing access to customer billing and usage data to a subscriber organization;
14. Establish customer engagement rules and minimum rules for education, contract reviews, and continued engagement;
15. Require net financial savings for low-income customers, as that term is defined in § 56-594.3, of at least 10 percent, relative to the subscription fee throughout the life of the subscription; and
16. 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. Within 180 days of finalization of the Commission's adoption of regulations for the shared solar program, a utility shall begin crediting subscriber accounts of each shared solar facility interconnected in its service territory, subject to the requirements of this section and regulations adopted thereto.
Repealed by Acts 2003, c. 885.
A. In all relevant proceedings pursuant to this Act, the Commission shall take into consideration, among other things, the goal of economic development in the Commonwealth.
B. By September 1 of each year, the Commission shall report to the Commission on Electric Utility Regulation and the Governor on the status of the implementation of this chapter and its recommendations regarding the implementation of the provisions of this chapter. This report shall include the Commission's recommendations for any actions by the General Assembly, the Commission, electric utilities, or any other entity that the Commission considers to be in the public interest.
It is the objective of the General Assembly that the construction and development of new utility-owned and utility-operated generating facilities utilizing energy derived from sunlight and from wind with an aggregate capacity of 5,000 megawatts, including rooftop solar installations with a capacity of not less than 50 kilowatts, and with an aggregate capacity of 50 megawatts, be placed in service on or before July 1, 2028. It is also the objective of the General Assembly that 2,700 megawatts of aggregate energy storage capacity be placed into service on or before July 1, 2030. The Commission shall submit a report and make recommendations to the Governor and the General Assembly annually on or before December 1 of each year through December 1, 2028, assessing (i) the aggregate annual new construction and development of new utility-owned and utility-operated generating facilities utilizing energy derived from sunlight, (ii) the integration of utility-owned renewable electric generation resources with the utility's electric distribution grid, (iii) the aggregate additional utility-owned and utility-operated generating facilities utilizing energy derived from sunlight placed in operation since July 1, 2018, (iv) the need for additional generation of electricity utilizing energy derived from sunlight in order to meet the objective of the General Assembly on or before July 1, 2028, and (v) the aggregate annual new construction or purchase of energy storage facilities. The Commission shall submit copies of such annual reports to the Chairman of the House Committee on Labor and Commerce, the Chairman of the Senate Committee on Commerce and Labor, and the Chairman of the Commission on Electric Utility Regulation.
A. Notwithstanding subsection G of § 56-580, or any other provision of law, each incumbent investor-owned electric utility shall develop proposed energy efficiency programs. Any program shall provide for the submission of a petition or petitions for approval to design, implement, and operate energy efficiency programs pursuant to subdivision A 5 c of § 56-585.1. At least 15 percent of such proposed costs of energy efficiency programs shall be allocated to programs designed to benefit low-income, elderly, or disabled individuals or veterans.
B. Notwithstanding any other provision of law, each investor-owned incumbent electric utility shall implement energy efficiency programs and measures to achieve the following total annual energy savings:
1. For Phase I electric utilities:
a. In calendar year 2022, at least 0.5 percent of the average annual energy jurisdictional retail sales by that utility in 2019;
b. In calendar year 2023, at least 1.0 percent of the average annual energy jurisdictional retail sales by that utility in 2019;
c. In calendar year 2024, at least 1.5 percent of the average annual energy jurisdictional retail sales by that utility in 2019; and
d. In calendar year 2025, at least 2.0 percent of the average annual energy jurisdictional retail sales by that utility in 2019;
2. For Phase II electric utilities:
a. In calendar year 2022, at least 1.25 percent of the average annual energy jurisdictional retail sales by that utility in 2019;
b. In calendar year 2023, at least 2.5 percent of the average annual energy jurisdictional retail sales by that utility in 2019;
c. In calendar year 2024, at least 3.75 percent of the average annual energy jurisdictional retail sales by that utility in 2019; and
d. In calendar year 2025, at least 5.0 percent of the average annual energy jurisdictional retail sales by that utility in 2019;
3. For the time period 2026 through 2028, the Commission shall, after notice and hearing, establish new energy efficiency savings targets measured as a percentage of the average annual energy jurisdictional retail sales by that utility in 2019; and
4. For the time period 2029 through 2031, and for every successive three-year period thereafter, the Commission shall establish new energy efficiency savings targets measured as a percentage of the average annual energy jurisdictional retail sales by that utility in 2019, which shall be the greatest level of energy savings that the Commission finds is feasible and cost-effective pursuant to the Commission's cost-effectiveness test regulations. To assist the Commission in setting such targets, the Commission shall retain a qualified expert, compensated pursuant to subsection E of § 56-592.1, to independently conduct an energy efficiency potential study for each Phase I and Phase II Utility's service territory, and each such utility shall provide to the Commission and its expert any information necessary to complete such study if such information is reasonably available. For every subsequent three-year period, the Commission shall retain an expert, compensated pursuant to subsection E of § 56-592.1, to update the energy efficiency potential study for each Phase I and Phase II Utility's service territory. A utility may recover any costs it incurs to assist the Commission with the energy efficiency potential study if the Commission finds such costs are reasonable and prudent. Such costs shall not be considered when determining whether an energy efficiency measure or program is cost-effective. In advance of the effective date of such targets, the Commission shall, after notice and opportunity for hearing, initiate proceedings to establish such targets. As part of such proceeding, the Commission shall consider the feasibility of achieving energy efficiency goals and future energy efficiency savings through cost-effective programs and measures. The Commission shall annually review the feasibility of the energy efficiency program savings in this section and report to the Chairs of the House Committee on Labor and Commerce and the Senate Committee on Commerce and Labor and the Secretary of Natural and Historic Resources and the Secretary of Commerce and Trade on such feasibility by October 1, 2022, and each year thereafter.
C. The projected costs for the utility to design, implement, and operate such energy efficiency programs and portfolios of programs shall be no less than an aggregate amount of $140 million for a Phase I Utility and $870 million for a Phase II Utility for the period beginning July 1, 2018, and ending July 1, 2028, including any existing approved energy efficiency programs. In developing such portfolio of energy efficiency programs and portfolios of programs, each utility shall utilize a stakeholder process, to be facilitated by an independent monitor compensated under the funding provided pursuant to subsection E of § 56-592.1, to provide input and feedback on (i) the development of such energy efficiency programs and portfolios of programs; (ii) compliance with the total annual energy savings set forth in this subsection and how such savings affect utility integrated resource plans; (iii) recommended policy reforms by which the General Assembly or the Commission can ensure maximum and cost-effective deployment of energy efficiency technology across the Commonwealth; and (iv) best practices for evaluation, measurement, and verification for the purposes of assessing compliance with the total annual energy savings set forth in subsection B. Utilities shall utilize the services of a third party to perform evaluation, measurement, and verification services to determine a utility's total annual savings as required by this subsection, as well as the annual and lifecycle net and gross energy and capacity savings, related emissions reductions, and other quantifiable benefits of each program; total customer bill savings that the programs and portfolios produce; and utility spending on each program, including any associated administrative costs. The third-party evaluator shall include and review each utility's avoided costs and cost-benefit analyses. The findings and reports of such third parties shall be concurrently provided to both the Commission and the utility, and the Commission shall make each such final annual report easily and publicly accessible online. Such stakeholder process shall include the participation of representatives from each utility, relevant directors, deputy directors, and staff members of the Commission who participate in approval and oversight of utility energy efficiency savings programs, the office of Consumer Counsel of the Attorney General, the Department of Energy, energy efficiency program implementers, energy efficiency providers, residential and small business customers, and any other interested stakeholder whom the independent monitor deems appropriate for inclusion in such process. The independent monitor shall convene meetings of the participants in the stakeholder process not less frequently than twice in each calendar year during the period beginning July 1, 2019, and ending July 1, 2028. The independent monitor shall report on the status of the energy efficiency stakeholder process, including (a) the objectives established by the stakeholder group during this process related to programs to be proposed, (b) recommendations related to programs to be proposed that result from the stakeholder process, and (c) the status of those recommendations, in addition to the petitions filed and the determination thereon, to the Governor, the Commission, and the Chairmen of the House Committee on Labor and Commerce and the Senate Committee on Commerce and Labor on July 1, 2019, and annually thereafter through July 1, 2028.
D. Nothing in this section shall apply to any entity organized under Chapter 9.1 (§ 56-231.15 et seq.).
2018, c. 296; 2019, cc. 397, 398; 2020, cc. 1193, 1194, 1208; 2021, Sp. Sess. I, cc. 401, 532; 2024, cc. 794, 818.
A. Each Phase I and Phase II Utility, as such terms are defined in subdivision A 1 of § 56-585.1, shall submit a petition for approval to design, implement, and operate a three-year program of energy conservation measures providing incentives to low-income, elderly, and disabled individuals in an amount not to exceed $25 million in the aggregate for the installation of measures that reduce residential heating or cooling costs and enhance the health and safety of residents, including repairs and improvements to home heating or cooling systems and installation of energy-saving measures in the house, such as insulation and air sealing. In developing such incentive program, each utility shall utilize the stakeholder process set forth in § 56-596.2. The utility may provide such incentives directly to customers or to organizations that assist low-income, elderly, and disabled individuals. Such incentive program shall be deemed to be a part of the $140 million in energy efficiency programs that a Phase I utility is required to develop pursuant to § 56-596.2 and a part of the $870 million in energy efficiency programs that a Phase II utility is required to develop pursuant to § 56-596.2; provided that no portion of such incentive programs shall be deemed to be a part of the required five percent of such energy conservation measures set aside for low-income, elderly, and disabled individuals.
B. For (i) low-income, elderly, and disabled individuals or (ii) organizations providing residential services to low-income, elderly, and disabled individuals who participate in, or have already participated in, an incentive program, including the incentive program described in subsection A, for the installation of measures that reduce heating or cooling costs at any premises where people reside, each Phase I and Phase II Utility shall submit a petition for approval to design, implement, and operate a separate three-year incentive program, in an amount not to exceed $25 million in the aggregate, to enable the installation of, or access to, equipment to generate electric energy derived from sunlight. The utility may provide such incentives directly to customers or to organizations that assist low-income, elderly, and disabled individuals. Such incentive program may include installation of equipment directly on the premises or access to equipment located elsewhere, provided such installation or access reduces the total energy costs for persons described in clause (i) or (ii). Such incentive program shall not be deemed to be a part of the $140 million in energy efficiency programs that a Phase I utility is required to develop pursuant to § 56-596.2 nor a part of the $870 million in energy efficiency programs that a Phase II utility is required to develop pursuant to § 56-596.2.
C. In developing such incentive programs, each utility shall give consideration to low-income, elderly, and disabled persons residing in housing that a redevelopment and housing authority owns or controls.
The State Corporation Commission (the Commission) shall establish for Phase II Utilities annual energy efficiency savings targets for customers who are low-income, elderly, disabled, or veterans of military service to be achieved through utility energy efficiency programs (low-income energy efficiency savings programs) designed to benefit such customers, provided that each year's target shall be measured by the total combined kilowatt-hour savings achieved by electric utility energy efficiency and demand response programs and measures installed for such customers in that program year, as well as savings still being achieved by measures and programs implemented for such customers in prior years, and that such annual targets shall be at least one percent of the average annual energy retail sales by that utility to those customers, to the extent that the potential exists and is reasonably achievable as determined by the Commission.
In establishing such targets, the Commission shall seek to optimize energy efficiency and the health and safety benefits of utility energy efficiency programs.
In advance of the effective date of such annual energy efficiency targets, the first of which shall be for 2025, the Commission shall, after notice and opportunity for hearing, initiate proceedings to establish such targets and the appropriate retail sales against which the energy efficiency targets will be measured.
In setting such targets, the Commission shall consider the impact and savings of energy efficiency programs authorized by subdivision C 2 of § 10.1-1330 of the Code of Virginia. The Commission shall also consider federal loan guarantees, grant funds, and rebates made available pursuant to the federal Inflation Reduction Act (P.L. 117-169) or other similar federal legislation that facilitates energy efficiency projects.
The Commission shall, for the period 2028 through 2030, review and, at its discretion, revise such minimum annual targets to ensure continued consistency with the provisions of this section.
All savings from low-income energy efficiency programs shall be applied to the energy efficiency savings set forth in subsection B of § 56-596.2 of the Code of Virginia.
In providing such low-income energy efficiency programs, Phase II Utilities shall make best efforts to coordinate such energy efficiency programs with any health and safety upgrades provided through energy efficiency programs authorized by subdivision C 2 of § 10.1-1330 of the Code of Virginia, when reasonably feasible to do so and at the utility's sole discretion.
For the purposes of this act, "Phase II Utility" has the same meaning as provided in subdivision A 1 of § 56-585.1 of the Code of Virginia.
2023, c. 728.
The Commission shall submit a report and make recommendations to the Governor and the General Assembly annually on or before December 1 of each year assessing (i) the reliability of electrical transmission or distribution systems; (ii) the integration of utility or customer owned renewable electric generation resources with the utility's electric distribution grid; (iii) the level of investment in generation, transmission, or distribution of electricity; (iv) the need for additional generation of electricity during times of peak demand; and (v) distribution system hardening projects and enhanced physical security measures. The Commission shall submit copies of such annual reports to the Chairman of the House Committee on Labor and Commerce, the Chairman of the Senate Committee on Commerce and Labor and the Chairman of the Commission on Electric Utility Regulation.
2018, c. 296.
A. For the purposes of this section, "Phase II Utility" has the same meaning as provided in subdivision A 1 of § 56-585.1.
B. Upon request of a locality located within the service territory of a Phase II Utility, a Phase II Utility shall provide local reliability data within 30 days of such request. The data provided to the locality shall be limited in scope to the particular locality that made the request. Such data provided by the utility shall include standard reliability metrics used in accordance with industry-recognized electric reliability standards (IEEE 1366), including data from the System Average Interruption Duration Index (SAIDI), the System Average Interruption Frequency Index (SAIFI), the Customer Average Interruption Duration Index (CAIDI), and the Customer Average Interruption Frequency Index (CAIFI). The Commission shall include in the report required pursuant to § 56-596.3 such industry standard reliability metrics for each Phase II Utility and a description of any infrastructure investments made by each Phase II Utility to improve electric service reliability over the relevant reporting period.
2022, c. 653.
