HB469: Electric utilities; clean energy mandates, transitioning workers, etc.

HOUSE BILL NO. 469

Offered January 12, 2022
Prefiled January 11, 2022
A BILL to amend and reenact §§ 10.1-1308, 45.2-1706.1, 45.2-1710, 56-585.1, 56-585.5, and 56-596.2 of the Code of Virginia and to amend the Code of Virginia by adding in Chapter 17 of Title 45.2 an article numbered 9, consisting of sections numbered 45.2-1734 through 45.2-1743, relating to carbon allowances; clean energy mandates; fossil fuel project moratorium; energy efficiency; transitioning workers; environmental justice; Climate Action Plan; recovery of cost of clean energy facilities; Commonwealth Clean Energy Policy; civil penalties; New Virginia Economy Act.
Patron-- Rasoul

Committee Referral Pending

Be it enacted by the General Assembly of Virginia:

1. That §§ 10.1-1308, 45.2-1706.1, 45.2-1710, 56-585.1, 56-585.5, and 56-596.2 of the Code of Virginia are amended and reenacted and that the Code of Virginia is amended by adding in Chapter 17 of Title 45.2 an article numbered 9, consisting of sections numbered 45.2-1734 through 45.2-1743, as follows:

§ 10.1-1308. Regulations.

A. The Board, after having studied air pollution in the various areas of the Commonwealth, its causes, prevention, control and abatement, shall have the power to promulgate regulations, including emergency regulations, abating, controlling and prohibiting air pollution throughout or in any part of the Commonwealth in accordance with the provisions of the Administrative Process Act (§ 2.2-4000 et seq.), except that a description of provisions of any proposed regulation which are more restrictive than applicable federal requirements, together with the reason why the more restrictive provisions are needed, shall be provided to the standing committee of each house of the General Assembly to which matters relating to the content of the regulation are most properly referable. No such regulation shall prohibit the burning of leaves from trees by persons on property where they reside if the local governing body of the county, city or town has enacted an otherwise valid ordinance regulating such burning. The regulations shall not promote or encourage any substantial degradation of present air quality in any air basin or region which has an air quality superior to that stipulated in the regulations. Any regulations adopted by the Board to have general effect in part or all of the Commonwealth shall be filed in accordance with the Virginia Register Act (§ 2.2-4100 et seq.).

B. Any regulation that prohibits the selling of any consumer product shall not restrict the continued sale of the product by retailers of any existing inventories in stock at the time the regulation is promulgated.

C. Any regulation requiring the use of stage 1 vapor recovery equipment at gasoline dispensing facilities may be applicable only in areas that have been designated at any time by the U.S. Environmental Protection Agency as nonattainment for the pollutant ozone. For purposes of this section, gasoline dispensing facility means any site where gasoline is dispensed to motor vehicle tanks from storage tanks.

D. No regulation of the Board shall require permits for the construction or operation of qualified fumigation facilities, as defined in § 10.1-1308.01.

E. Notwithstanding any other provision of law and no earlier later than July 1, 2024 2025, the Board shall adopt regulations to reduce, for the period of 2031 2030 to 2050 2035, the carbon dioxide emissions from any electricity generating unit in the Commonwealth, regardless of fuel type, that serves an electricity generator with a nameplate capacity equal to or greater than 25 megawatts that supplies (i) 10 percent or more of its annual net electrical generation to the electric grid or (ii) more than 15 percent of its annual total useful energy to any entity other than the manufacturing facility to which the generating source is interconnected (covered unit).

The Board may establish, implement, and manage an auction program to sell allowances to carry out the purposes of such regulations or may in its discretion utilize an existing multistate trading system.

The Board may utilize its existing regulations to reduce carbon dioxide emissions from electric power generating facilities; however, the regulations shall provide that no allowances be issued for covered units in 2050 2035 or any year beyond 2050 2035. The Board may establish rules for trading, the use of banked allowances, and other auction or market mechanisms as it may find appropriate to control allowance costs and otherwise carry out the purpose of this subsection.

In adopting such regulations, the Board shall consider only the carbon dioxide emissions from the covered units. The Board shall not provide for emission offsetting or netting based on fuel type.

Regulations adopted by the Board under this subsection shall be subject to the requirements set out in §§ 2.2-4007.03, 2.2-4007.04, 2.2-4007.05, and 2.2-4026 through 2.2-4030 of the Administrative Process Act (§ 2.2-4000 et seq.) and shall be published in the Virginia Register of Regulations.

§ 45.2-1706.1. Commonwealth Clean Energy Policy.

A. The Commonwealth recognizes that effectively addressing climate change and enhancing resilience will advance the health, welfare, and safety of the residents of the Commonwealth. The Commonwealth further recognizes that addressing climate change requires reducing greenhouse gas emissions across the Commonwealth's economy sufficient to reach net-zero emission zero emissions by 2045 2035 in all sectors, including the electric power, transportation, industrial, agricultural, building, and infrastructure sectors. To achieve these objectives, it shall be the policy of the Commonwealth to:

1. Develop clean energy resources necessary to produce 30 80 percent of Virginia's electricity from renewable clean energy sources by 2030 and 100 percent of Virginia's electricity from carbon-free sources by 2040 2035;

2. Enable widespread integration of distributed energy resources, including energy storage and rooftop solar, into the grid to achieve decarbonization and to enhance resilience;

3. Support the distributed generation of renewable and clean electricity by:

a. Encouraging private sector investments in distributed renewable and clean energy;

b. Increasing the security of the electricity grid by supporting distributed renewable and clean energy projects and energy storage with the potential to supply electric energy to critical facilities during a widespread power outage; and

c. Enhancing the ability of private property owners to generate their own renewable and clean energy for their own personal use from renewable and clean energy sources on their property;

4. Lead by example in state government by supporting the carbon-free energy resources required to fully decarbonize the electric power supply of the Commonwealth, including deploying 30 80 percent renewables clean energy by 2030, realizing 100 percent carbon-free electric power by 2040 2035, and achieving net zero emissions by 2045 2035;

5. Maximize energy efficiency programs as defined in § 56-576, to the extent determined to be in the public interest, that are the lowest-cost energy option to reduce greenhouse gas emissions, in order to produce electricity cost savings and to create jobs and economic opportunity from the energy efficiency sector;

6. Support net-zero emission zero-emission targets by promoting zero-emission vehicles and infrastructure, including electrified transport, decreasing the carbon intensity of the transportation sector, by electrification of personal, commercial, and farm vehicles and public transportation; encouraging alternative transportation options,; and increasing the efficiency of motor vehicles operating on Virginia's roads;

7. Support electric distribution grid transformation projects as defined in § 56-576;

8. Promote building and construction practices that reduce emissions associated with built environment, including energy efficiency targets, new building standards, and transit-oriented and other sustainable development practices; and

9. Ensure that energy development projects avoid, minimize, and, if necessary, mitigate damage to the Commonwealth's natural and cultural resources.

B. The Commonwealth recognizes the need to promote environmental justice and ensure that it is carried out throughout the Commonwealth, as provided in § 2.2-235, and the need to address and prevent energy inequities in historically economically disadvantaged communities, as defined in § 56-576. To achieve these objectives, it shall be the policy of the Commonwealth to:

1. Recognize the disproportionate and inequitable impacts of climate change on historically economically disadvantaged communities and prioritize solutions and investment in these communities to maximize the benefits of clean energy and minimize the burdens of climate change;

2. Ensure the fair treatment and meaningful involvement, as those terms are defined in § 2.2-234, of all people regardless of race, color, national origin, faith, disability, or income with respect to the administration of energy laws, regulations, and policies; and

3. Increase access to clean energy and the benefits from clean energy to historically economically disadvantaged communities.

C. As Virginia transforms its energy economy, the Commonwealth must continue to prioritize economic competiveness and workforce development in an equitable manner. To achieve this objective, it shall be the policy of the Commonwealth to:

1. Equitably incorporate requirements for technical, policy, and economic analyses and assessments that recognize the unique attributes of different energy resources and delivery systems to identify pathways to net-zero zero carbon that maximize Virginia's energy reliability and resilience, economic development, and jobs;

2. Require that pathways to net-zero zero greenhouse gas emissions be determined on the basis of technical, policy, and economic analysis to maximize their effectiveness, optimize Virginia's economic development, support industrial employment, and create quality jobs while minimizing adverse impacts on public health, affected communities, and the environment;

3. Ensure an adequate energy supply and a Virginia-based energy production capacity, while also optimizing intrastate and interstate use of energy supply and delivery to maximize energy availability, reliability, and price opportunities to the benefit of all user classes and the Commonwealth's economy;

4. Increase wind energy development and grow the Commonwealth's role as a wind industry hub for offshore wind generation projects in state and federal waters off the United States coast;

5. Ensure the availability of reliable energy at costs that are reasonable and in quantities that will support the Commonwealth's economy;

6. Ensure reliable energy availability in the event of a disruption occurring to a portion of the Commonwealth's energy matrix and to address the needs of businesses during the transition to clean energy;

7. Minimize the Commonwealth's long-term exposure to volatility and increases in world energy prices by expanding the use of innovative clean energy technology within the Commonwealth;

8. Create training opportunities and green career pathways for local workers and workers in historically economically disadvantaged communities in onshore and offshore wind, solar energy, electrification, energy efficiency, clean transportation, and other emerging clean energy industries;

9. Support the repurposing and development of clean energy resources on previously developed project sites as defined in § 56-576;

10. Ensure that decision making is transparent and includes opportunities for full participation by the public;

11. Explore approaches to maximizing and leveraging the capacity of lands and waters in the Commonwealth to store energy; and

12. Increase the Commonwealth's reliance on and production of sustainably produced biofuels made from traditional agricultural crops and other feedstocks, such as winter cover crops, warm season grasses, fast-growing trees, algae, or other suitable feedstocks grown in the Commonwealth, that will (i) create jobs and income,; (ii) produce clean-burning fuels that will help to improve air quality,; and (iii) provide the new markets for Virginia's silvicultural and agricultural products needed to preserve farm employment, conserve farmland and forestland, and increase implementation of silvicultural and agricultural best management practices to protect water quality.

D. The elements of the policy set forth in subsections A, B, and C shall be referred to collectively in this title as the Commonwealth Clean Energy Policy.

E. All agencies and political subdivisions of the Commonwealth, in taking discretionary action with regard to energy issues, shall recognize the elements of the Commonwealth Clean Energy Policy and, where appropriate, shall act in a manner consistent therewith.

F. The Commonwealth Clean Energy Policy is intended to provide guidance to the agencies and political subdivisions of the Commonwealth in taking discretionary action with regard to energy issues and shall not be construed to amend, repeal, or override any contrary provision of applicable law. Nothing in this section shall preclude reliable access to electricity and natural gas during the transition to renewable clean energy. The failure or refusal of any person to recognize the elements of the Commonwealth Clean Energy Policy, to act in a manner consistent with the Commonwealth Clean Energy Policy, or to take any other action whatsoever shall not create any right, action, or cause of action or provide standing for any person to challenge the action of the Commonwealth or any of its agencies or political subdivisions.

§ 45.2-1710. Development of the Virginia Energy Plan.

A. The Division, in consultation with the State Corporation Commission, the Department of Environmental Quality, the Clean Energy Advisory Board, the solar, wind, energy efficiency, and transportation electrification sectors, and a stakeholder group that includes representatives of consumer, environmental, manufacturing, forestry, and agricultural organizations and natural gas and electric utilities, shall prepare a comprehensive Virginia Energy Plan (the Plan) that identifies actions over a 10-year period consistent with the goal of the Commonwealth Clean Energy Policy set forth in § 45.2-1706.1 to achieve, no later than 2045 2035, a net-zero zero carbon energy economy for all sectors, including the electricity, transportation, building, agricultural, and industrial sectors. The Plan shall propose actions, consistent with the objectives enumerated in § 45.2-1706.1, that will implement the Commonwealth Clean Energy Policy set forth in § 45.2-1706.1.

B. In addition, the Plan shall include:

1. Projections of energy consumption in the Commonwealth, including the use of fuel sources and costs of electricity, natural gas, gasoline, coal, renewable and clean energy resources, and other forms of non-greenhouse-gas-generating energy resources, such as nuclear power, used in the Commonwealth;

2. An analysis of the adequacy of electricity generation, transmission, and distribution resources in the Commonwealth for the natural gas and electric industries, and how distributed energy resources and regional generation, transmission, and distribution resources affect the Commonwealth;

3. An analysis of siting requirements for electric generation resources and natural gas and electric transmission and distribution resources, including an assessment of state and local impediments to expanded use of distributed resources and recommendations to reduce or eliminate such impediments;

4. An analysis of fuel diversity for electricity generation, recognizing the importance of flexibility in meeting future capacity needs;

5. An analysis of the efficient use of energy resources and conservation initiatives;

6. An analysis of how such Virginia-specific issues relate to regional initiatives to ensure the adequacy of fuel production, generation, transmission, and distribution assets;

7. An analysis of the siting of energy resource development, refining, and transmission facilities to identify any disproportionate adverse impact of such activities on economically disadvantaged or minority communities;

8. With regard to any regulations proposed or adopted by the U.S. Environmental Protection Agency to reduce carbon dioxide emissions from fossil fuel-fired electric generating units under § 111(d) of the federal Clean Air Act, 42 U.S.C. § 7411(d), an analysis of (i) the costs to and benefits for energy producers and electric utility customers, (ii) the effect on energy markets and reliability, and (iii) the commercial availability of technology required to comply with such regulations;

9. An inventory of greenhouse gas emissions compiled using a method determined by the Department of Environmental Quality for the four years prior to the issuance of the Plan;

10. Data regarding the number and type of electric and hybrid electric vehicles currently registered in the Commonwealth; projections of future electric vehicle sales across all vehicle classes, taking into consideration the impact of current and potential statewide policies; and analysis of the impact that of the growth of electrified transit on the Commonwealth's electric system;

11. An analysis of the Commonwealth's current electric vehicle charging infrastructure and all future infrastructure needed to support the 2045 net-zero 2035 zero carbon emissions target in the transportation sector, including chargers, make-ready electrical equipment, and supporting hardware and software needed to support the electrification of all vehicle categories used on and off roads and highways, including light-duty, medium-duty, and heavy-duty vehicles and electric bicycles, as well as that needed to electrify ground transportation at all ports and airports, with particular attention to the needs of historically economically disadvantaged communities as defined in § 56-576 and any state or local impediments to deployment; and

12. Recommendations, based on the analyses completed under subdivisions 1 through 11, for legislative, regulatory, and other public and private actions to implement the elements of the Commonwealth Clean Energy Policy.

C. In preparing the Plan, the Division and other agencies involved in the planning process shall utilize state geographic information systems, to the extent deemed practicable, to assess how recommendations in the Plan may affect pristine natural areas and other significant onshore natural resources. Effective October 1, 2024, interim updates on the Plan shall also contain projections for greenhouse gas emissions that would result from implementation of the Plan's recommendations.

D. In preparing the Plan, the Division and other agencies involved in the planning process shall develop a system for assigning numerical scores to any parcel of real property based on the extent to which such parcel is suitable for the siting of a wind energy facility or solar energy facility. For a wind energy facility, the scoring system shall address the wind velocity, sustained velocity, and turbulence. For either a wind energy facility or a solar energy facility, the scoring system shall address the parcel's proximity to electric power transmission lines or systems, potential impacts of such a facility to natural and historic resources and to economically disadvantaged or minority communities, and compatibility with the local land use plan. The system developed pursuant to this section shall allow the suitability of the parcel for the siting of a wind energy or solar energy facility to be compared to the suitability of other parcels so scored, and shall be based on a scale that allows the suitability of the parcel for the siting of such a facility to be measured against the hypothetical score of an ideal location for such a facility.

E. Upon receipt by the Division of a recommendation from the Department of General Services, a local governing body, or the parcel's owner stating that a parcel of real property is a potentially suitable location for a wind energy facility or solar energy facility, the Division shall analyze the suitability of the parcel for the location of such a facility. In conducting its analysis, the Division shall ascribe a numerical score to the parcel using the scoring system developed pursuant to subsection D.

Article 9.
Clean Energy Transition Plan.

§ 45.2-1734. Definitions.

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

"Clean energy" means energy efficiency, energy conservation, demand response, energy storage, and energy derived from solar, onshore wind, offshore wind, geothermal, and ocean tidal sources.

"Environmental justice community" has the same meaning as provided in § 2.2-234.

"Fossil fuel" or "fossil fuel resource" means coal, petroleum, natural gas, landfill gas, or gas derived from agricultural waste, as that term is defined in § 56-265.1, or any derivative of coal, petroleum, natural gas, landfill gas, or gas derived from agricultural waste that is used for fuel.

"Fossil fuel energy" means electric energy generated, in whole or in part, by a fossil fuel resource.

"Gathering line" has the same meaning ascribed to the term in 49 C.F.R. § 195.2.

"Permitting agency" means the Department, State Corporation Commission, State Air Pollution Control Board, State Water Control Board, Virginia Waste Management Board, Department of Environmental Quality, or other state agency or political subdivision of the Commonwealth that is the issuing agent for any permit, certificate, or other approval that is required to be obtained prior to the construction or operation of any facility described in subsection A of § 45.2-1736.

"Retail electric supplier" means a public utility or other person that (i) sold not less than 1,000 megawatt hours of electric energy to retail customers during the preceding calendar year or (ii) generates not less than 1,000 megawatt hours of electric energy for use by the person.

§ 45.2-1735. Clean energy mandates.

A. The minimum annual percentage of the quantity of electricity sold by a retail electric supplier that is generated from clean energy resources shall be:

1. In calendar years 2030 through 2034, 80 percent; and

2. In calendar year 2035 and every calendar year thereafter, 100 percent.

B. Beginning in 2023, by April 1 of each year, each retail electric supplier shall submit a report to the Director containing:

1. Documentation of purchases or generation by the retail electric supplier of clean energy-sourced electricity as a percentage of the total retail electricity sales of the retail electric supplier in the preceding calendar year; and

2. Documentation of plans for the purchase or generation by the retail electric supplier of clean energy-sourced electricity equal to the percentage required by this article for retail electricity sales in 2030 through 2034 and in 2035 and every year thereafter.

§ 45.2-1736. Moratorium on new major fossil fuel projects.

A. Beginning on January 1, 2023, unless preempted by applicable federal law, there shall be a moratorium on approval by any permitting agency of any permit, certificate, or other approval required for:

1. Any new electric generating facility that generates fossil fuel energy through the combustion of any fossil fuel resource;

2. Any new or expanding import or export terminal for fossil fuel resources;

3. Any maintenance activity relating to an existing import or export terminal for a fossil fuel resource that expands the import or export capacity for a fossil fuel resource;

4. Any new gathering line or transmission pipeline for the transport of any fossil fuel resource that requires the use of eminent domain on private property;

5. Any maintenance activity relating to an existing gathering line or transmission pipeline for the transport of a fossil fuel resource that expands the carrying capacity of the gathering line or pipeline by more than five percent;

6. Any new refinery of a fossil fuel resource; and

7. Any exploration for any type of fossil fuel.

B. Unless preempted by applicable federal law, the applicable permitting agency shall deny any application submitted to such permitting agency on or after January 1, 2023, for a permit, certificate, or approval for the construction, installation, expansion, or operation of any facility or activity described in subsection A. The State Corporation Commission shall not find any rate case brought as a result of these provisions to be reasonable and competent. However, nothing in this section shall be construed to mandate denial of an application submitted to a permitting agency for development, expansion, maintenance, or operation of small distribution pipelines that transport fossil fuel resources directly to residential or commercial customers of a retail electric supplier.

§ 45.2-1737. Authority of Director; enforcement of article by injunction.

A. The Director shall promulgate such rules and regulations as may be necessary and proper to carry out the provisions of this article.

B. The authority to administer and enforce the provisions of this article is hereby vested in the Director. In administering and enforcing the provisions of this article, the Director shall exercise the following powers in addition to any other powers conferred upon him by law:

1. To supervise the administration and enforcement of this article and all rules and regulations and orders adopted hereunder;

2. To issue orders to enforce the provisions of this article and all rules and regulations promulgated hereunder;

3. To make investigations and inspections to ensure compliance with any provision of this article or any rules, regulations, or orders promulgated or issued hereunder; and

4. To receive any federal funds, state funds, or any other funds and to enter into any contracts for which funds are available to carry out the purposes of this article.

C. The Director may petition any court of competent jurisdiction for an injunction against any violation of the provisions of this article and the rules, regulations, and orders promulgated or issued hereunder or to compel the performance of acts required thereby without regard to any adequate remedy that may exist at law, such injunction to be issued without bond.

D. The Director shall administer the Just Transition Fund pursuant to § 45.2-1738.

§ 45.2-1738. Just Transition Fund.

A. There is hereby created in the state treasury a special nonreverting fund to be known as the Just Transition Fund, referred to in this section as "the Fund." The Fund shall be established on the books of the Comptroller. All funds appropriated for such purpose and any gifts, donations, grants, bequests, and other funds received on its behalf 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 specified in this article and for the Department's direct and indirect costs of administering the Fund.

B. To provide funds to establish and operate the Fund, the Department shall, after notice and opportunity for hearing, initiate a proceeding to establish the rates, terms, and conditions of a monthly assessment on Phase I and Phase II Utilities, as those terms are defined in subdivision A 1 of § 56-585.1. The assessment shall be in proportion to the gross revenue on business conducted in the Commonwealth by each Phase I and Phase II Utility. Each Phase I and Phase II Utility operating in the Commonwealth shall, starting on the first of each month after such assessment proceeding has concluded, pay an assessment, in the form and manner prescribed by the Department, to be remitted, along with all other moneys received by the Department for the same purpose, to the Fund. Any Phase I or Phase II Utility that fails to pay the assessment on or before the date it is due shall be subject to a penalty imposed by the Department. The penalty shall be ten percent of the assessment and interest shall be charged at a rate pursuant to § 58.1-1812 for the period between the date due and the date of full payment. The Department shall be reimbursed from the Fund for all expenses necessary for the administration of this section. In the event there is a surplus in the Fund, the Department may reduce the assessment due from Phase I and Phase II Utilities for future months in accordance with the surplus. No Phase I or Phase II Utility shall recoup the cost of such assessment from its ratepayers by adding additional service fees to utility bills or otherwise.

C. The Fund shall be used for the following purposes:

1. To create state programs to support clean energy development and energy efficiency, including by making funds available for local governments to administer when appropriate;

2. To provide grants and low-interest or no-interest loans to residential customers, nonprofits, and local governments to support clean energy development and energy efficiency;

3. To create local job training programs, placement programs, and economic diversification programs for communities that will experience decreased tax revenues due to the transition away from fossil fuels pursuant to the Climate Action Plan in § 45.2-1739; and

4. To create grants for brownfield redevelopment and former fossil fuel infrastructure site reclamation, separate from the Virginia Brownfield and Coal Mine Renewable Energy Grant Program established pursuant to § 45.2-1725, but consistent with the provisions of subsection D of § 45.2-1725.

D. The Fund shall provide prevailing wages, project labor agreements, or public workers for all projects that receive funding from the Fund for purposes of administering the Climate Action Plan adopted pursuant to § 45.2-1739. The Fund shall provide assistance to transitioning workers and protections for workers in the clean energy and energy efficiency sectors pursuant to the Transitioning Workers Program established in § 45.2-1741.

§ 45.2-1739. Climate Action Plan; Environmental and Climate Justice Task Force.

A. The Department shall adopt a Climate Action Plan to implement the requirements established in this article. The Climate Action Plan shall:

1. Address all aspects of climate change, including mitigation, adaptation, and resiliency;

2. Address agriculture and transportation;

3. Address the Commonwealth's goal to reduce the energy consumption associated with buildings provided in § 45.2-1740;

4. Support the development of community and publicly owned clean energy;

5. Incorporate goals of environmental justice and be developed with meaningful input and analysis from environmental justice organizations and communities;

6. Recognize (i) the right of all people to clean air, safe and affordable drinking water, protection from climate hazards, and sustainable preservation and (ii) the inherent value of ecological integrity and maintaining the natural environment; and

7. Be completed by January 1, 2024, with a draft plan available for public comment by March 1, 2023.

B. The Department shall conduct regional public hearings on the draft plan and provide publicly available translations of the draft and final plan in English, Spanish, Korean, Vietnamese, Chinese, Hindi, Arabic, and any other language necessary to allow access to individuals with limited English proficiency.

C. Permitting agencies shall take action and adopt regulations that are consistent with and further the goals of the Climate Action Plan. Each permitting agency shall develop and update annually a plan to achieve such goals for its own internal operations as well as for regulatory and other actions under its purview.

D. The Department shall ensure that the Climate Action Plan (i) will advance the goal of 100 percent clean energy in a manner that benefits the Commonwealth's most disadvantaged communities and is transparent and accountable to the public and the General Assembly; (ii) achieves the required emissions reductions equitably and in a manner that protects and, where feasible, improves the condition of low-income and moderate-income persons; (iii) prevents increases in the emissions of toxic air contaminants and criteria air pollutants including emissions of nitrous oxide, sulfur dioxide, and mercury; and (iv) maximizes additional environmental and economic benefits for the Commonwealth.

E. The Climate Action Plan shall ensure that 40 percent of funds allocated by and through the Commonwealth to deal with climate change shall be targeted to low-income communities and communities of color.

F. The Department shall appoint and convene a state Environmental and Climate Justice Task Force (the Task Force) for the purpose of advising the Department on the implementation of the Climate Action Plan. The Task Force shall provide recommendations on methods for a just transition to 100 percent clean energy in the Commonwealth. All such recommendations shall be developed in accordance with a framework established by the Department that includes a specific evaluation of whether the Climate Action Plan is consistent with the goals of environmental protection; protecting the health, safety, and welfare of the residents of the Commonwealth; community development; and equitable treatment across industries and communities. The Task Force shall consist of representatives from labor unions, nonprofit environmental organizations, environmental justice organizations and communities, fossil fuel transition communities, public interest groups, and tribal and indigenous communities.

The Task Force shall carry out its duties to ensure:

1. The availability and accessibility of quality information related to the implementation of the Climate Action Plan for all people in the Commonwealth;

2. Appropriate and differential consideration of the different needs of residents in environmental justice communities, low-income communities, and communities of color in ways that do not compromise the quality and affordability of clean energy for those residents;

3. Elimination of barriers to the development of clean energy resources and to the introduction and availability of new technologies related to successful implementation of the Climate Action Plan for those residents described in subdivision 2; and

4. Compliance with the goals of the Climate Action Plan.

§ 45.2-1740. Energy efficiency and electrification of buildings.

A. The Commonwealth shall have a stated goal of reducing the consumption of electric energy for heating, cooling, lighting, and appliances in buildings within the Commonwealth by 2036 to a level that is 36 percent less than the quantity of electricity that would reasonably be projected to be consumed in the Commonwealth for such purposes in 2035 in the absence of such actions. Such goal shall have benchmark goals of 2.4 percent per year of the electric energy consumption for such purposes from 2021 levels.

B. The Commonwealth shall have a stated goal of electrifying all heating, cooling, lighting, and appliances in residential and commercial buildings within the Commonwealth by 2035.

§ 45.2-1741. Transitioning Workers Program.

A. The Department, in conjunction with the Virginia Board of Workforce Development, shall establish the Transitioning Workers Program (the Program) to provide support for workers in the fossil fuel industry and affected communities. The Program shall provide such workers job training, relocation support, income and benefit support, and early retirement benefits. The Program shall be designed to ensure transitioning workers are able to maintain or surpass their previous income and benefits and shall include the development of trade programs in high schools and community colleges, and scholarships and forgivable education loans for workers who transition to the clean energy and energy efficiency sectors.

B. The Department shall develop guidelines for protections for transitioning workers and workers in the clean energy and energy efficiency sectors. Such guidelines shall require the use of project labor agreements or otherwise provide for the payment of a prevailing wage for clean energy and energy efficiency jobs, and protect the rights of individuals to freely join a union without interference from employers.

C. The Department, in implementing the Program, shall consult with the Environmental and Climate Justice Task Force established in subsection F of § 45.2-1739. Funds from the Just Transition Fund established in § 45.2-1738 shall be used to implement the Program.

§ 45.2-1742. Environmental justice protections.

A. The Department, in coordination with the Virginia Council on Environmental Justice (the Council), shall establish performance benchmarks for environmental justice communities. Such benchmarks shall:

1. Mandate that 40 percent of funding for energy efficiency programs in the Commonwealth be directed to energy efficiency measures in environmental justice communities until such date that energy efficacy goals in environmental justice communities are attained; and

2. Mandate that 40 percent of funding for programs directed at attaining annual clean energy goals be directed to investments in clean energy facilities in environmental justice communities until such date that 100 percent of the energy consumed in such communities is clean energy.

B. The Department, in coordination with the Council, shall establish programs for jobs for people in environmental justice communities. Such programs:

1. Shall provide scholarships and low-interest loans for job training programs prioritized for individuals living in environmental justice communities;

2. Shall ensure that job training programs exist in environmental justice communities and are adequate to meet employment goals; and

3. May grant preference in hiring and promotion to residents of environmental justice communities, notwithstanding any local or state equal employment opportunity law.

C. The Department, in coordination with the Council, shall provide meaningful input and analysis in planning for energy transition and energy efficiency from environmental justice communities throughout the Commonwealth. In implementing this requirement, the Department shall:

1. Establish statewide and regional bodies responsible for developing, evaluating, and providing feedback on meeting environmental justice priorities; and

2. Hold multiple public hearings in environmental justice communities on transition plans.

D. The Department shall ensure that benefits for low-income communities are specific and realized. The Department shall prevent the use of compliance payment or other offsets to meet clean energy and energy efficiency goals.

E. In order to provide accountability for meeting environmental justice benchmarks, the Department shall:

1. Require annual reporting on progress, including specifics on goals for environmental justice communities;

2. Require shareholders, and not ratepayers, to be responsible for civil penalties assessed against a retail electric supplier pursuant to § 45.2-1743 for failure to meet any goal or benchmark; and

3. Conduct, if any goal or benchmark established by this article is not met, an analysis as to why the goal or benchmark was not met and develop a plan to make up from the missed goal or benchmark in subsequent years.

F. The permitting agencies of the Commonwealth shall:

1. Require a cumulative impact analysis or a reasonable certainty of no harm to the health and welfare of the general public, or to any potentially exposed or susceptible subpopulation, before issuing permits; or, if there is no certainty of no harm, then the permit shall include terms to ensure reasonable certainty of no harm;

2. Establish agency-wide strategies regarding environmental justice that identify and address any disproportionately high or adverse human health effects of the agency's programs and comply with environmental justice benchmarks with regular reporting and revision; and

3. Within one year of the enactment of this article, require agency employees to complete an environmental justice training program and require the same of new employees thereafter.

G. After approval of the Climate Action Plan in § 45.2-1739, the Council, Department, and the permitting agencies of the Commonwealth shall (i) make every effort to grant any necessary approvals to construct, acquire, or enter into agreements to purchase the energy, capacity, and environmental attributes of energy derived from renewable or clean sources located in the Commonwealth and (ii) assist with retiring generation facilities that use the process of combusting fuel to produce electricity.

§ 45.2-1743. Civil penalties.

Any retail electric supplier that fails to meet any goal or benchmark established under this article, upon such finding by an appropriate circuit court, shall be assessed a civil penalty equal to twice the cost of the financial investment necessary to meet such goal or mandate that was not achieved, or three times the cost of the financial investment necessary to meet such goal or benchmark that was not achieved if not met in an environmental justice community. All civil penalties under this section shall be recovered in a civil action brought by the Attorney General in the name of the Commonwealth. All civil penalties assessed under this section shall be paid into the general fund.

§ 56-585.1. Generation, distribution, and transmission rates after capped rates terminate or expire.

A. During the first six months of 2009, the Commission shall, after notice and opportunity for hearing, initiate proceedings to review the rates, terms and conditions for the provision of generation, distribution and transmission services of each investor-owned incumbent electric utility. Such proceedings shall be governed by the provisions of Chapter 10 (§ 56-232 et seq.), except as modified herein. In such proceedings the Commission shall determine fair rates of return on common equity applicable to the generation and distribution services of the utility. In so doing, the Commission may use any methodology to determine such return it finds consistent with the public interest, but such return shall not be set lower than the average of the returns on common equity reported to the Securities and Exchange Commission for the three most recent annual periods for which such data are available by not less than a majority, selected by the Commission as specified in subdivision 2 b, of other investor-owned electric utilities in the peer group of the utility, nor shall the Commission set such return more than 300 basis points higher than such average. The peer group of the utility shall be determined in the manner prescribed in subdivision 2 b. The Commission may increase or decrease such combined rate of return by up to 100 basis points based on the generating plant performance, customer service, and operating efficiency of a utility, as compared to nationally recognized standards determined by the Commission to be appropriate for such purposes. In such a proceeding, the Commission shall determine the rates that the utility may charge until such rates are adjusted. If the Commission finds that the utility's combined rate of return on common equity is more than 50 basis points below the combined rate of return as so determined, it shall be authorized to order increases to the utility's rates necessary to provide the opportunity to fully recover the costs of providing the utility's services and to earn not less than such combined rate of return. If the Commission finds that the utility's combined rate of return on common equity is more than 50 basis points above the combined rate of return as so determined, it shall be authorized either (i) to order reductions to the utility's rates it finds appropriate, provided that the Commission may not order such rate reduction unless it finds that the resulting rates will provide the utility with the opportunity to fully recover its costs of providing its services and to earn not less than the fair rates of return on common equity applicable to the generation and distribution services; or (ii) to direct that 60 percent of the amount of the utility's earnings that were more than 50 basis points above the fair combined rate of return for calendar year 2008 be credited to customers' bills, in which event such credits shall be amortized over a period of six to 12 months, as determined at the discretion of the Commission, following the effective date of the Commission's order and be allocated among customer classes such that the relationship between the specific customer class rates of return to the overall target rate of return will have the same relationship as the last approved allocation of revenues used to design base rates. Commencing in 2011, the Commission, after notice and opportunity for hearing, shall conduct reviews of the rates, terms and conditions for the provision of generation, distribution and transmission services by each investor-owned incumbent electric utility, subject to the following provisions:

1. Rates, terms and conditions for each service shall be reviewed separately on an unbundled basis, and such reviews shall be conducted in a single, combined proceeding. Pursuant to subsection A of § 56-585.1:1, the Commission shall conduct a review for a Phase I Utility in 2020, utilizing the three successive 12-month test periods beginning January 1, 2017, and ending December 31, 2019. Thereafter, reviews for a Phase I Utility will be on a triennial basis with subsequent proceedings utilizing the three successive 12-month test periods ending December 31 immediately preceding the year in which such review proceeding is conducted. Pursuant to subsection A of § 56-585.1:1, the Commission shall conduct a review for a Phase II Utility in 2021, utilizing the four successive 12-month test periods beginning January 1, 2017, and ending December 31, 2020, with subsequent reviews on a triennial basis utilizing the three successive 12-month test periods ending December 31 immediately preceding the year in which such review proceeding is conducted. All such reviews occurring after December 31, 2017, shall be referred to as triennial reviews. For purposes of this section, a Phase I Utility is an investor-owned incumbent electric utility that was, as of July 1, 1999, not bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002, and a Phase II Utility is an investor-owned incumbent electric utility that was bound by such a settlement.

2. Subject to the provisions of subdivision 6, the fair rate of return on common equity applicable separately to the generation and distribution services of such utility, and for the two such services combined, and for any rate adjustment clauses approved under subdivision 5 or 6, shall be determined by the Commission during each such triennial review, as follows:

a. The Commission may use any methodology to determine such return it finds consistent with the public interest, but 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. 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. For purposes of this subdivision, an investor-owned electric utility shall be deemed part of such peer group if (i) its principal operations are conducted in the southeastern United States east of the Mississippi River in either the states of West Virginia or Kentucky or in those states south of Virginia, excluding the state of Tennessee, (ii) it is a vertically-integrated electric utility providing generation, transmission and distribution services whose facilities and operations are subject to state public utility regulation in the state where its principal operations are conducted, (iii) it had a long-term bond rating assigned by Moody's Investors Service of at least Baa at the end of the most recent test period subject to such triennial review, and (iv) it is not an affiliate of the utility subject to such triennial review.

c. The Commission may, consistent with its precedent for incumbent electric utilities prior to the enactment of Chapters 888 and 933 of the Acts of Assembly of 2007, increase or decrease the utility's combined rate of return based on the Commission's consideration of the utility's performance.

d. In any Current Proceeding, the Commission shall determine whether the Current Return has increased, on a percentage basis, above the Initial Return by more than the increase, expressed as a percentage, in the United States Average Consumer Price Index for all items, all urban consumers (CPI-U), as published by the Bureau of Labor Statistics of the United States Department of Labor, since the date on which the Commission determined the Initial Return. If so, the Commission may conduct an additional analysis of whether it is in the public interest to utilize such Current Return for the Current Proceeding then pending. A finding of whether the Current Return justifies such additional analysis shall be made without regard to any enhanced rate of return on common equity awarded pursuant to the provisions of subdivision 6. Such additional analysis shall include, but not be limited to, a consideration of overall economic conditions, the level of interest rates and cost of capital with respect to business and industry, in general, as well as electric utilities, the current level of inflation and the utility's cost of goods and services, the effect on the utility's ability to provide adequate service and to attract capital if less than the Current Return were utilized for the Current Proceeding then pending, and such other factors as the Commission may deem relevant. If, as a result of such analysis, the Commission finds that use of the Current Return for the Current Proceeding then pending would not be in the public interest, then the lower limit imposed by subdivision 2 a on the return to be determined by the Commission for such utility shall be calculated, for that Current Proceeding only, by increasing the Initial Return by a percentage at least equal to the increase, expressed as a percentage, in the United States Average Consumer Price Index for all items, all urban consumers (CPI-U), as published by the Bureau of Labor Statistics of the United States Department of Labor, since the date on which the Commission determined the Initial Return. For purposes of this subdivision:

"Current Proceeding" means any proceeding conducted under any provisions of this subsection that require or authorize the Commission to determine a fair combined rate of return on common equity for a utility and that will be concluded after the date on which the Commission determined the Initial Return for such utility.

"Current Return" means the minimum fair combined rate of return on common equity required for any Current Proceeding by the limitation regarding a utility's peer group specified in subdivision 2 a.

"Initial Return" means the fair combined rate of return on common equity determined for such utility by the Commission on the first occasion after July 1, 2009, under any provision of this subsection pursuant to the provisions of subdivision 2 a.

e. In addition to other considerations, in setting the return on equity within the range allowed by this section, the Commission shall strive to maintain costs of retail electric energy that are cost competitive with costs of retail electric energy provided by the other peer group investor-owned electric utilities.

f. The determination of such returns shall be made by the Commission on a stand-alone basis, and specifically without regard to any return on common equity or other matters determined with regard to facilities described in subdivision 6.

g. If the combined rate of return on common equity earned by the generation and distribution services is no more than 50 basis points above or below the return as so determined or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, such return is no more than 70 basis points above or below the return as so determined, such combined return shall not be considered either excessive or insufficient, respectively. However, for any test period commencing after December 31, 2012, for a Phase II Utility, and after December 31, 2013, for a Phase I Utility, if the utility has, during the test period or periods under review, earned below the return as so determined, whether or not such combined return is within 70 basis points of the return as so determined, the utility may petition the Commission for approval of an increase in rates in accordance with the provisions of subdivision 8 a as if it had earned more than 70 basis points below a fair combined rate of return, and such proceeding shall otherwise be conducted in accordance with the provisions of this section. The provisions of this subdivision are subject to the provisions of subdivision 8.

h. Any amount of a utility's earnings directed by the Commission to be credited to customers' bills pursuant to this section shall not be considered for the purpose of determining the utility's earnings in any subsequent triennial review.

3. Each such utility shall make a triennial filing by March 31 of every third year, with such filings commencing for a Phase I Utility in 2020, and such filings commencing for a Phase II Utility in 2021, consisting of the schedules contained in the Commission's rules governing utility rate increase applications. Such filing shall encompass the three successive 12-month test periods ending December 31 immediately preceding the year in which such proceeding is conducted, except that the filing for a Phase II Utility in 2021 shall encompass the four successive 12-month test periods ending December 31, 2020, and in every such case the filing for each year shall be identified separately and shall be segregated from any other year encompassed by the filing. If the Commission determines that rates should be revised or credits be applied to customers' bills pursuant to subdivision 8 or 9, any rate adjustment clauses previously implemented related to facilities utilizing simple-cycle combustion turbines described in subdivision 6, shall be combined with the utility's costs, revenues and investments until the amounts that are the subject of such rate adjustment clauses are fully recovered. The Commission shall combine such clauses with the utility's costs, revenues and investments only after it makes its initial determination with regard to necessary rate revisions or credits to customers' bills, and the amounts thereof, but after such clauses are combined as herein specified, they shall thereafter be considered part of the utility's costs, revenues, and investments for the purposes of future triennial review proceedings. In a triennial filing under this subdivision that does not result in an overall rate change a utility may propose an adjustment to one or more tariffs that are revenue neutral to the utility.

4. (Expires December 31, 2023) The following costs incurred by the utility shall be deemed reasonable and prudent: (i) costs for transmission services provided to the utility by the regional transmission entity of which the utility is a member, as determined under applicable rates, terms and conditions approved by the Federal Energy Regulatory Commission; (ii) costs charged to the utility that are associated with demand response programs approved by the Federal Energy Regulatory Commission and administered by the regional transmission entity of which the utility is a member; and (iii) costs incurred by the utility to construct, operate, and maintain transmission lines and substations installed in order to provide service to a business park. Upon petition of a utility at any time after the expiration or termination of capped rates, but not more than once in any 12-month period, the Commission shall approve a rate adjustment clause under which such costs, including, without limitation, costs for transmission service; charges for new and existing transmission facilities, including costs incurred by the utility to construct, operate, and maintain transmission lines and substations installed in order to provide service to a business park; administrative charges; and ancillary service charges designed to recover transmission costs, shall be recovered on a timely and current basis from customers. Retail rates to recover these costs shall be designed using the appropriate billing determinants in the retail rate schedules.

4. (Effective January 1, 2024) The following costs incurred by the utility shall be deemed reasonable and prudent: (i) costs for transmission services provided to the utility by the regional transmission entity of which the utility is a member, as determined under applicable rates, terms and conditions approved by the Federal Energy Regulatory Commission, and (ii) costs charged to the utility that are associated with demand response programs approved by the Federal Energy Regulatory Commission and administered by the regional transmission entity of which the utility is a member. Upon petition of a utility at any time after the expiration or termination of capped rates, but not more than once in any 12-month period, the Commission shall approve a rate adjustment clause under which such costs, including, without limitation, costs for transmission service, charges for new and existing transmission facilities, administrative charges, and ancillary service charges designed to recover transmission costs, shall be recovered on a timely and current basis from customers. Retail rates to recover these costs shall be designed using the appropriate billing determinants in the retail rate schedules.

5. A utility may at any time, after the expiration or termination of capped rates, but not more than once in any 12-month period, petition the Commission for approval of one or more rate adjustment clauses for the timely and current recovery from customers of the following costs:

a. Incremental costs described in clause (vi) of subsection B of § 56-582 incurred between July 1, 2004, and the expiration or termination of capped rates, if such utility is, as of July 1, 2007, deferring such costs consistent with an order of the Commission entered under clause (vi) of subsection B of § 56-582. The Commission shall approve such a petition allowing the recovery of such costs that comply with the requirements of clause (vi) of subsection B of § 56-582;

b. Projected and actual costs for the utility to design and operate fair and effective peak-shaving programs 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 and clean 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:

Type of Generation Facility

Basis Points

First Portion of Service Life

Nuclear-powered

200

Between 12 and 25 years

Carbon capture compatible, clean-coal powered

200

Between 10 and 20 years

Renewable powered, other than landfill gas powered

200

Between 5 and 15 years

Coalbed methane gas powered

150

Between 5 and 15 years

Landfill gas powered

200

Between 5 and 15 years

Conventional coal or combined-cycle combustion turbine

100

Between 10 and 20 years

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 triennial review proceeding, provide for a customer credit reinvestment offset, as applicable, pursuant to subdivision 8 d with respect to all costs deemed reasonable and prudent by the Commission in a proceeding pursuant to subsection D of § 56-580 or in a triennial review proceeding.

Electric distribution grid transformation projects are in the public interest. To the extent that a utility elects to recover the costs of such electric distribution grid transformation projects through its rates for generation and distribution services, and does not petition and receive approval from the Commission for recovery of such costs through a rate adjustment clause described in clause (vi), the Commission shall, upon the request of the utility in a triennial review proceeding, provide for a customer credit reinvestment offset, as applicable, pursuant to subdivision 8 d with respect to all costs deemed reasonable and prudent by the Commission in a proceeding for approval of a plan for electric distribution grid transformation projects pursuant to subdivision 6 or in a triennial review proceeding.

Neither generation facilities described in clause (ii) that utilize simple-cycle combustion turbines nor new underground facilities shall receive an enhanced rate of return on common equity as described herein, but instead shall receive the utility's general rate of return during the construction phase of the facility and, thereafter, for the entire service life of the facility. No rate adjustment clause for new underground facilities shall allocate costs to, or provide for the recovery of costs from, customers that are served within the large power service rate class for a Phase I Utility and the large general service rate classes for a Phase II Utility. New underground facilities are hereby declared to be ordinary extensions or improvements in the usual course of business under the provisions of § 56-265.2.

As used in this subdivision, a generation facility is (1) "coalbed methane gas powered" if the facility is fired at least 50 percent by coalbed methane gas, as such term is defined in § 45.2-1600, 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 1,500 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.

Notwithstanding any other provision of this subdivision, the provisions of §§ 56-585.1:11 and 56-585.5, or any other provision of law, all costs associated with the construction of, acquisition of, or agreements to purchase the energy, capacity, and environmental attributes of any generation or storage facility of which the construction, acquisition, or agreements to purchase are required by § 56-585.1:11 or 56-585.5 shall be recovered through the utility's rates for generation and distribution services.

7. Any petition filed pursuant to subdivision 4, 5, or 6 shall be considered by the Commission on a stand-alone basis without regard to the other costs, revenues, investments, or earnings of the utility. Any costs incurred by a utility prior to the filing of such petition, or during the consideration thereof by the Commission, that are proposed for recovery in such petition and that are related to subdivision 5 a, or that are related to facilities and projects described in clause (i) of subdivision 6, or that are related to new underground facilities described in clause (iv) of subdivision 6, shall be deferred on the books and records of the utility until the Commission's final order in the matter, or until the implementation of any applicable approved rate adjustment clauses, whichever is later. Except as otherwise provided in subdivision 6, any costs prudently incurred on or after July 1, 2007, by a utility prior to the filing of such petition, or during the consideration thereof by the Commission, that are proposed for recovery in such petition and that are related to facilities and projects described in clause (ii) or clause (iii) of subdivision 6 that utilize nuclear power, or coal-fueled facilities and projects described in clause (ii) of subdivision 6 if such coal-fueled facilities will be built by a Phase I Utility, shall be deferred on the books and records of the utility until the Commission's final order in the matter, or until the implementation of any applicable approved rate adjustment clauses, whichever is later. Any costs prudently incurred after the expiration or termination of capped rates related to other matters described in subdivision 4, 5, or 6 shall be deferred beginning only upon the expiration or termination of capped rates, provided, however, that no provision of this act shall affect the rights of any parties with respect to the rulings of the Federal Energy Regulatory Commission in PJM Interconnection LLC and Virginia Electric and Power Company, 109 F.E.R.C. P 61,012 (2004). A utility shall establish a regulatory asset for regulatory accounting and ratemaking purposes under which it shall defer its operation and maintenance costs incurred in connection with (i) the refueling of any nuclear-powered generating plant and (ii) other work at such plant normally performed during a refueling outage. The utility shall amortize such deferred costs over the refueling cycle, but in no case more than 18 months, beginning with the month in which such plant resumes operation after such refueling. The refueling cycle shall be the applicable period of time between planned refueling outages for such plant. As of January 1, 2014, such amortized costs are a component of base rates, recoverable in base rates only ratably over the refueling cycle rather than when such outages occur, and are the only nuclear refueling costs recoverable in base rates. This provision shall apply to any nuclear-powered generating plant refueling outage commencing after December 31, 2013, and the Commission shall treat the deferred and amortized costs of such regulatory asset as part of the utility's costs for the purpose of proceedings conducted (a) with respect to triennial filings under subdivision 3 made on and after July 1, 2014, and (b) pursuant to § 56-245 or the Commission's rules governing utility rate increase applications as provided in subsection B. This provision shall not be deemed to change or reset base rates.

The Commission's final order regarding any petition filed pursuant to subdivision 4, 5, or 6 shall be entered not more than three months, eight months, and nine months, respectively, after the date of filing of such petition. If such petition is approved, the order shall direct that the applicable rate adjustment clause be applied to customers' bills not more than 60 days after the date of the order, or upon the expiration or termination of capped rates, whichever is later.

8. In any triennial review proceeding, for the purposes of reviewing earnings on the utility's rates for generation and distribution services, the following utility generation and distribution costs not proposed for recovery under any other subdivision of this subsection, as recorded per books by the utility for financial reporting purposes and accrued against income, shall be attributed to the test periods under review and deemed fully recovered in the period recorded: costs associated with asset impairments related to early retirement determinations made by the utility for utility generation facilities fueled by coal, natural gas, or oil or for automated meter reading electric distribution service meters; costs associated with projects necessary to comply with state or federal environmental laws, regulations, or judicial or administrative orders relating to coal combustion by-product management that the utility does not petition to recover through a rate adjustment clause pursuant to subdivision 5 e; costs associated with severe weather events; and costs associated with natural disasters. Such costs shall be deemed to have been recovered from customers through rates for generation and distribution services in effect during the test periods under review unless such costs, individually or in the aggregate, together with the utility's other costs, revenues, and investments to be recovered through rates for generation and distribution services, result in the utility's earned return on its generation and distribution services for the combined test periods under review to fall more than 50 basis points below the fair combined rate of return authorized under subdivision 2 for such periods or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, to fall more than 70 basis points below the fair combined rate of return authorized under subdivision 2 for such periods. In such cases, the Commission shall, in such triennial review proceeding, authorize deferred recovery of such costs and allow the utility to amortize and recover such deferred costs over future periods as determined by the Commission. The aggregate amount of such deferred costs shall not exceed an amount that would, together with the utility's other costs, revenues, and investments to be recovered through rates for generation and distribution services, cause the utility's earned return on its generation and distribution services to exceed the fair rate of return authorized under subdivision 2, less 50 basis points, for the combined test periods under review or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, to exceed the fair rate of return authorized under subdivision 2 less 70 basis points. Nothing in this section shall limit the Commission's authority, pursuant to the provisions of Chapter 10 (§ 56-232 et seq.), including specifically § 56-235.2, following the review of combined test period earnings of the utility in a triennial review, for normalization of nonrecurring test period costs and annualized adjustments for future costs, in determining any appropriate increase or decrease in the utility's rates for generation and distribution services pursuant to subdivision 8 a or 8 c.

If the Commission determines as a result of such triennial review that:

a. 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. In any triennial review proceeding conducted after January 1, 2020, for a Phase I Utility or after January 1, 2021, for a Phase II Utility in which the utility has, during the test period or test periods under review, considered as a whole, earned more than 50 basis points above a fair combined rate of return on its generation and distribution services or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, more than 70 basis points above a fair combined rate of return on its generation and distribution services, as determined in subdivision 2, without regard to any return on common equity or other matter determined with respect to facilities described in subdivision 6, and the combined aggregate level of capital investment that the Commission has approved other than those capital investments that the Commission has approved for recovery pursuant to a rate adjustment clause pursuant to subdivision 6 made by the utility during the test periods under review in that triennial review proceeding in new utility-owned generation facilities utilizing energy derived from sunlight, or from wind, and in electric distribution grid transformation projects, as determined pursuant to subdivision 8 d, does not equal or exceed 100 percent of the earnings that are more than 70 basis points above the utility's fair combined rate of return on its generation and distribution services for the combined test periods under review in that triennial review proceeding, the Commission shall, subject to the provisions of subdivision 9 and in addition to the actions authorized in subdivision b, also order reductions to the utility's rates it finds appropriate. However, in the first triennial review proceeding conducted after January 1, 2021, for a Phase II Utility, any reduction to the utility's rates ordered by the Commission pursuant to this subdivision shall not exceed $50 million in annual revenues, with any reduction allocated to the utility's rates for generation services, and in each triennial review of a Phase I or Phase II Utility, the Commission may not order such rate reduction unless it finds that the resulting rates will provide the utility with the opportunity to fully recover its costs of providing its services and to earn not less than a fair combined rate of return on its generation and distribution services, as determined in subdivision 2, without regard to any return on common equity or other matters determined with respect to facilities described in subdivision 6, using the most recently ended 12-month test period as the basis for determining the permissibility of any rate reduction under the standards of this sentence, and the amount thereof; and

d. (Expires July 1, 2028) In any triennial review proceeding conducted after December 31, 2017, upon the request of the utility, the Commission shall determine, prior to directing that 70 percent of earnings that are more than 70 basis points above the utility's fair combined rate of return on its generation and distribution services for the test period or periods under review be credited to customer bills pursuant to subdivision 8 b, the aggregate level of prior capital investment that the Commission has approved other than those capital investments that the Commission has approved for recovery pursuant to a rate adjustment clause pursuant to subdivision 6 made by the utility during the test period or periods under review in both (i) new utility-owned generation facilities utilizing energy derived from sunlight, or from onshore or offshore wind, and (ii) electric distribution grid transformation projects, as determined by the utility's plant in service and construction work in progress balances related to such investments as recorded per books by the utility for financial reporting purposes as of the end of the most recent test period under review. Any such combined capital investment amounts shall offset any customer bill credit amounts, on a dollar for dollar basis, up to the aggregate level of invested or committed capital under clauses (i) and (ii). The aggregate level of qualifying invested or committed capital under clauses (i) and (ii) is referred to in this subdivision as the customer credit reinvestment offset, which offsets the customer bill credit amount that the utility has invested or will invest in new solar or wind generation facilities or electric distribution grid transformation projects for the benefit of customers, in amounts up to 100 percent of earnings that are more than 70 basis points above the utility's fair rate of return on its generation and distribution services, and thereby reduce or eliminate otherwise incremental rate adjustment clause charges and increases to customer bills, which is deemed to be in the public interest. If 100 percent of the amount of earnings that are more than 70 basis points above the utility's fair combined rate of return on its generation and distribution services, as determined in subdivision 2, exceeds the aggregate level of invested capital in new utility-owned generation facilities utilizing energy derived from sunlight, or from wind, and electric distribution grid transformation projects, as provided in clauses (i) and (ii), during the test period or periods under review, then 70 percent of the amount of such excess shall be credited to customer bills as provided in subdivision 8 b in connection with the triennial review proceeding. The portion of any costs associated with new utility-owned generation facilities utilizing energy derived from sunlight, or from wind, or electric distribution grid transformation projects that is the subject of any customer credit reinvestment offset pursuant to this subdivision shall not thereafter be recovered through the utility's rates for generation and distribution services over the service life of such facilities and shall not thereafter be included in the utility's costs, revenues, and investments in future triennial review proceedings conducted pursuant to subdivision 2 and shall not be the subject of a rate adjustment clause petition pursuant to subdivision 6. The portion of any costs associated with new utility-owned generation facilities utilizing energy derived from sunlight, or from wind, or electric distribution grid transformation projects that is not the subject of any customer credit reinvestment offset pursuant to this subdivision may be recovered through the utility's rates for generation and distribution services over the service life of such facilities and shall be included in the utility's costs, revenues, and investments in future triennial review proceedings conducted pursuant to subdivision 2 until such costs are fully recovered, and if such costs are recovered through the utility's rates for generation and distribution services, they shall not be the subject of a rate adjustment clause petition pursuant to subdivision 6. Only the portion of such costs of new utility-owned generation facilities utilizing energy derived from sunlight, or from wind, or electric distribution grid transformation projects that has not been included in any customer credit reinvestment offset pursuant to this subdivision, and not otherwise recovered through the utility's rates for generation and distribution services, may be the subject of a rate adjustment clause petition by the utility pursuant to subdivision 6.

The Commission's final order regarding such triennial review shall be entered not more than eight months after the date of filing, and any revisions in rates or credits so ordered shall take effect not more than 60 days after the date of the order. The fair combined rate of return on common equity determined pursuant to subdivision 2 in such triennial review shall apply, for purposes of reviewing the utility's earnings on its rates for generation and distribution services, to the entire three successive 12-month test periods ending December 31 immediately preceding the year of the utility's subsequent triennial review filing under subdivision 3 and shall apply to applicable rate adjustment clauses under subdivisions 5 and 6 prospectively from the date the Commission's final order in the triennial review proceeding, utilizing rate adjustment clause true-up protocols as the Commission in its discretion may determine.

9. If, as a result of a triennial review required under this subsection and conducted with respect to any test period or periods under review ending later than December 31, 2010 (or, if the Commission has elected to stagger its biennial reviews of utilities as provided in subdivision 1, under review ending later than December 31, 2010, for a Phase I Utility, or December 31, 2011, for a Phase II Utility), the Commission finds, with respect to such test period or periods considered as a whole, that (i) any utility has, during the test period or periods under review, considered as a whole, earned more than 50 basis points above a fair combined rate of return on its generation and distribution services or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, more than 70 basis points above a fair combined rate of return on its generation and distribution services, as determined in subdivision 2, without regard to any return on common equity or other matters determined with respect to facilities described in subdivision 6, and (ii) the total aggregate regulated rates of such utility at the end of the most recently ended 12-month test period exceeded the annual increases in the United States Average Consumer Price Index for all items, all urban consumers (CPI-U), as published by the Bureau of Labor Statistics of the United States Department of Labor, compounded annually, when compared to the total aggregate regulated rates of such utility as determined pursuant to the review conducted for the base period, the Commission shall, unless it finds that such action is not in the public interest or that the provisions of subdivisions 8 b and c are more consistent with the public interest, direct that any or all earnings for such test period or periods under review, considered as a whole that were more than 50 basis points, or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, more than 70 basis points, above such fair combined rate of return shall be credited to customers' bills, in lieu of the provisions of subdivisions 8 b and c, provided that no credits shall be provided pursuant to this subdivision in connection with any triennial review unless such bill credits would be payable pursuant to the provisions of subdivision 8 d, and any credits under this subdivision shall be calculated net of any customer credit reinvestment offset amounts under subdivision 8 d. Any such credits shall be amortized and allocated among customer classes in the manner provided by subdivision 8 b. For purposes of this subdivision:

"Base period" means (i) the test period ending December 31, 2010 (or, if the Commission has elected to stagger its biennial reviews of utilities as provided in subdivision 1, the test period ending December 31, 2010, for a Phase I Utility, or December 31, 2011, for a Phase II Utility), or (ii) the most recent test period with respect to which credits have been applied to customers' bills under the provisions of this subdivision, whichever is later.

"Total aggregate regulated rates" shall include: (i) fuel tariffs approved pursuant to § 56-249.6, except for any increases in fuel tariffs deferred by the Commission for recovery in periods after December 31, 2010, pursuant to the provisions of clause (ii) of subsection C of § 56-249.6; (ii) rate adjustment clauses implemented pursuant to subdivision 4 or 5; (iii) revisions to the utility's rates pursuant to subdivision 8 a; (iv) revisions to the utility's rates pursuant to the Commission's rules governing utility rate increase applications, as permitted by subsection B, occurring after July 1, 2009; and (v) base rates in effect as of July 1, 2009.

10. For purposes of this section, the Commission shall regulate the rates, terms and conditions of any utility subject to this section on a stand-alone basis utilizing the actual end-of-test period capital structure and cost of capital of such utility, excluding any debt associated with securitized bonds that are the obligation of non-Virginia jurisdictional customers, unless the Commission finds that the debt to equity ratio of such capital structure is unreasonable for such utility, in which case the Commission may utilize a debt to equity ratio that it finds to be reasonable for such utility in determining any rate adjustment pursuant to subdivisions 8 a and c, and without regard to the cost of capital, capital structure, revenues, expenses or investments of any other entity with which such utility may be affiliated. In particular, and without limitation, the Commission shall determine the federal and state income tax costs for any such utility that is part of a publicly traded, consolidated group as follows: (i) such utility's apportioned state income tax costs shall be calculated according to the applicable statutory rate, as if the utility had not filed a consolidated return with its affiliates, and (ii) such utility's federal income tax costs shall be calculated according to the applicable federal income tax rate and shall exclude any consolidated tax liability or benefit adjustments originating from any taxable income or loss of its affiliates.

B. Nothing in this section shall preclude an investor-owned incumbent electric utility from applying for an increase in rates pursuant to § 56-245 or the Commission's rules governing utility rate increase applications; however, in any such filing, a fair rate of return on common equity shall be determined pursuant to subdivision A 2. Nothing in this section shall preclude such utility's recovery of fuel and purchased power costs as provided in § 56-249.6.

C. Except as otherwise provided in this section, the Commission shall exercise authority over the rates, terms and conditions of investor-owned incumbent electric utilities for the provision of generation, transmission and distribution services to retail customers in the Commonwealth pursuant to the provisions of Chapter 10 (§ 56-232 et seq.), including specifically § 56-235.2.

D. The Commission may determine, during any proceeding authorized or required by this section, the reasonableness or prudence of any cost incurred or projected to be incurred, by a utility in connection with the subject of the proceeding. A determination of the Commission regarding the reasonableness or prudence of any such cost shall be consistent with the Commission's authority to determine the reasonableness or prudence of costs in proceedings pursuant to the provisions of Chapter 10 (§ 56-232 et seq.). In determining the reasonableness or prudence of a utility providing energy and capacity to its customers from renewable energy resources, the Commission shall consider the extent to which such renewable energy resources, whether utility-owned or by contract, further the objectives of the Commonwealth 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 promulgate such rules and regulations as may be necessary to implement the provisions of this section.

§ 56-585.5. Generation of electricity from clean energy sources.

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.

"Clean energy" means energy efficiency, energy conservation, demand response, energy storage, and energy derived from solar, onshore wind, offshore wind, geothermal, and ocean tidal sources.

"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 retail supplier of electrical energy, including investor-owned utilities and electric cooperatives, 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, 2028, each Phase I and II Utility shall retire all biomass-fired electric generating units that do not co-fire with coal.

3. By December 31, 2045 2035, each Phase I and II Utility shall retire all other electric generating units located in the Commonwealth that emit carbon as a by-product use the process of combusting fuel to generate electricity.

4. Notwithstanding any other provision of law, 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. 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, (iii) biomass-fired facilities that are outside the Commonwealth, or (iv) biomass-fired facilities operating in the Commonwealth as of January 1, 2020, that supply 10 percent or more of their annual net electrical generation to the electric grid or 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. 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 forest or woody biomass as fuel; or (e) biomass-fired facilities in operation in the Commonwealth and in operation as of January 1, 2020, that 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. 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 2019; 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, or falling water electric generating resources in operation, or proposed for operation, in the Commonwealth or 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 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 through 2035

27% 80%

2029 through 2035

38% 80%

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 2036 and thereafter

100%

2046

84%

 

 

2047

88%

 

 

2048

92%

 

 

2049

96%

 

 

2050 2036 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 and clean 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 and clean 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. Nothing in this section shall apply to any entity organized under Chapter 9.1 (§ 56-231.15 et seq.).

J. 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

F. Any retail electric supplier that fails to meet the goals or mandate established by this section, upon such finding by an appropriate circuit court, shall be assessed a civil penalty equal to twice the cost of the financial investment necessary to meet such goal or mandate that was not achieved, or, for goals or mandates related to or located in an environmental justice community, three times the cost of the financial investment necessary to meet such goal or mandate that was not achieved. All civil penalties under this section shall be recovered in a civil action brought by the Attorney General in the name of the Commonwealth. All civil penalties assessed under this section shall be paid into the general fund.

§ 56-596.2. Energy efficiency programs; financial assistance for low-income customers.

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 40 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 low-income, elderly, or disabled individuals or veterans; and environmental justice communities, as defined in § 2.2-234.

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 and Phase II electric utilities:

a. In calendar year 2022 2023, at least 0.5 2.4 percent of the average annual energy jurisdictional retail sales by that utility in 2019 2021;

b. In calendar year 2023 2024, at least 1.0 4.8 percent of the average annual energy jurisdictional retail sales by that utility in 2019 2021;

c. In calendar year 2024 2025, at least 1.5 7.2 percent of the average annual energy jurisdictional retail sales by that utility in 2019 2021; and

d. In calendar year 2025 2026, at least 2.0 9.6 percent of the average annual energy jurisdictional retail sales by that utility in 2019 2021;

2. For Phase II electric utilities:

a. e. In calendar year 2022 2027, at least 1.25 12.0 percent of the average annual energy jurisdictional retail sales by that utility in 2019 2021;

b. f. In calendar year 2023 2028, at least 2.5 14.4 percent of the average annual energy jurisdictional retail sales by that utility in 2019 2021;

c. g. In calendar year 2024 2029, at least 3.75 16.8 percent of the average annual energy jurisdictional retail sales by that utility in 2019 2021; and

d. h. In calendar year 2025 2030, at least 5.0 19.2 percent of the average annual energy jurisdictional retail sales by that utility in 2019 2021; and

i. In calendar year 2031, at least 21.6 percent of the average annual energy jurisdictional retail sales by that utility in 2021;

j. In calendar year 2032, at least 24.0 percent of the average annual energy jurisdictional retail sales by that utility in 2021;

k. In calendar year 2033, at least 26.4 percent of the average annual energy jurisdictional retail sales by that utility in 2021;

l. In calendar year 2034, at least 28.8 percent of the average annual energy jurisdictional retail sales by that utility in 2021;

m. In calendar year 2035, at least 31.2 percent of the average annual energy jurisdictional retail sales by that utility in 2021;

n. In calendar year 2036, at least 33.6 percent of the average annual energy jurisdictional retail sales by that utility in 2021; and

o. In calendar year 2037, at least 36.0 percent of the average annual energy jurisdictional retail sales by that utility in 2021.

3. 2. For the time period 2026 2038 through 2028 2040, and for every successive three-year period thereafter, the Commission shall establish new energy efficiency savings targets. 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 2023, 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 2040, 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 2040. 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 2040.

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

2. That this act shall be known as the New Virginia Economy Act.