Be it enacted by the General Assembly of Virginia:

1. That §§10.1-1307, 10.1-1308, 10.1-1402.03, 10.1-1402.04, 45.2-1701.1, 56-585.1, 56-585.1:4, 56-585.3, and 56-585.8 of the Code of Virginia are amended and reenacted as follows:

§10.1-1307. Further powers and duties of Board and Department.

A. The Board shall have the power to control and regulate its internal affairs. The Department shall have the power to initiate and supervise research programs to determine the causes, effects, and hazards of air pollution; initiate and supervise statewide programs of air pollution control education; cooperate with and receive money from the federal government or any county or municipal government, and receive money from any other source, whether public or private; develop a comprehensive program for the study, abatement, and control of all sources of air pollution in the Commonwealth; and advise, consult, and cooperate with agencies of the United States and all agencies of the Commonwealth, political subdivisions, private industries, and any other affected groups in furtherance of the purposes of this chapter.

B. The Board may adopt by regulation emissions standards controlling the release into the atmosphere of air pollutants from motor vehicles, only as provided in §10.1-1307.05 and Article 22 (§46.2-1176 et seq.) of Chapter 10 of Title 46.2.

C. After any regulation has been adopted by the Board pursuant to §10.1-1308, the Department may grant local variances therefrom, if it finds after an investigation and hearing that local conditions warrant; except that no local variances shall be granted from regulations adopted by the Board pursuant to §10.1-1308 related to the requirements of subsection E of §10.1-1308 or Article 4 (§10.1-1329 et seq.). If local variances are permitted, the Department shall issue an order to this effect. Such order shall be subject to revocation or amendment at any time if the Department, after a hearing, determines that the amendment or revocation is warranted. Variances and amendments to variances shall be adopted only after a public hearing has been conducted pursuant to the public advertisement of the subject, date, time, and place of the hearing at least 30 days prior to the scheduled hearing. The hearing shall be conducted to give the public an opportunity to comment on the variance.

D. After the Board has adopted the regulations provided for in §10.1-1308, the Department shall have the power to (i) initiate and receive complaints as to air pollution; (ii) hold or cause to be held hearings and enter orders diminishing or abating the causes of air pollution and orders to enforce the Board's regulations pursuant to § 10.1-1309; and (iii) institute legal proceedings, including suits for injunctions for the enforcement of orders, regulations, and the abatement and control of air pollution and for the enforcement of penalties.

E. The Board in making regulations; the Department in approving variances, control programs, or permits; and the courts in granting injunctive relief under the provisions of this chapter, shall consider facts and circumstances relevant to the reasonableness of the activity involved and the regulations proposed to control it, including:

1. The character and degree of injury to, or interference with, safety, health, or the reasonable use of property which is caused or threatened to be caused;

2. The social and economic value of the activity involved;

3. The suitability of the activity to the area in which it is located, except that consideration of this factor shall be satisfied if the local governing body of a locality in which a facility or activity is proposed has resolved that the location and operation of the proposed facility or activity is suitable to the area in which it is located; and

4. The scientific and economic practicality of reducing or eliminating the discharge resulting from such activity.

F. The Department shall conduct the hearings provided for in this chapter.

G. The Board shall not:

1. Adopt any regulation limiting emissions from wood heaters; or

2. Enforce against a manufacturer, distributor, or consumer any federal regulation limiting emissions from wood heaters adopted after May 1, 2014.

H. D. The Department shall submit an annual report to the Governor and General Assembly on or before October 1 of each year on matters relating to the Commonwealth's air pollution control policies and on the status of the Commonwealth's air quality.

I. In granting a permit pursuant to this section, the Department shall provide in writing a clear and concise statement of the legal basis, scientific rationale, and justification for the decision reached. When the decision of the Department is to deny a permit, pursuant to this section, the Department shall, in consultation with legal counsel, provide a clear and concise statement explaining the reason for the denial, the scientific justification for the same, and how the Department's decision is in compliance with applicable laws and regulations. Copies of the decision, certified by the Director, shall be mailed by certified mail to the permittee or applicant.

§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 than July 1, 2024, the Board shall adopt regulations to reduce, for the period of 2031 to 2050, 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 or any year beyond 2050. 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.

§10.1-1402.03. Closure of certain coal combustion residuals units.

A. For the purposes of this section only:

"Carrying cost" means the cost associated with financing expenditures incurred but not yet recovered from the electric utility's customers, and shall be calculated by applying the electric utility's weighted average cost of debt and equity capital, as determined by the State Corporation Commission, with no additional margin or profit, to any unrecovered balances.

"CCR landfill" means an area of land or an excavation that receives CCR and is not a surface impoundment, underground injection well, salt dome formation, salt bed formation, underground or surface coal mine, or cave and that is owned or operated by an electric utility.

"CCR surface impoundment" means a natural topographic depression, man-made excavation, or diked area that (i) is designed to hold an accumulation of CCR and liquids; (ii) treats, stores, or disposes of CCR; and (iii) is owned or operated by an electric utility.

"CCR unit" means any CCR landfill, CCR surface impoundment, lateral expansion of a CCR unit, or combination of two or more such units that is owned by an electric utility. Notwithstanding the provisions of 40 C.F.R. Part 257, "CCR unit" also includes any CCR below the unit boundary of the CCR landfill or CCR surface impoundment.

"Coal combustion residuals" or "CCR" means fly ash, bottom ash, boiler slag, and flue gas desulfurization materials generated from burning coal for the purpose of generating electricity by an electric utility.

"Encapsulated beneficial use" means a beneficial use of CCR that binds the CCR into a solid matrix and minimizes its mobilization into the surrounding environment.

The definitions in this subsection shall be interpreted in a manner consistent with 40 C.F.R. Part 257, except as expressly provided in this section.

B. The owner or operator of any CCR unit located within the Chesapeake Bay watershed at the Bremo Power Station, Chesapeake Energy Center, Chesterfield Power Station, and Possum Point Power Station that ceased accepting CCR prior to July 1, 2019, shall complete closure of such unit by (i) removing all of the CCR in accordance with applicable standards established by Virginia Solid Waste Management Regulations (9VAC20-81) and (ii) either (a) beneficially reusing all such CCR in a recycling process for encapsulated beneficial use or (b) disposing of the CCR in a permitted landfill on the property upon which the CCR unit is located, adjacent to the property upon which the CCR unit is located, or off of the property on which the CCR unit is located, that includes, at a minimum, a composite liner and leachate collection system that meets or exceeds the federal Criteria for Municipal Solid Waste Landfills pursuant to 40 C.F.R. Part 258. The owner or operator shall beneficially reuse a total of no less than 6.8 million cubic yards in aggregate of such removed CCR from no fewer than two of the sites listed in this subsection where CCR is located.

C. The owner or operator shall complete the closure of any such CCR unit required by this section no later than 15 years after initiating the closure process at that CCR unit. During the closure process, the owner or operator shall, at its expense, offer to provide a connection to a municipal water supply, or where such connection is not feasible provide water testing, for any residence within one-half mile of the CCR unit.

D. Where closure pursuant to this section requires that CCR or CCR that has been beneficially reused be removed off-site, the owner or operator shall develop a transportation plan in consultation with any county, city, or town in which the CCR units are located and any county, city, or town within two miles of the CCR units that minimizes the impact of any transport of CCR on adjacent property owners and surrounding communities. The transportation plan shall include (i) alternative transportation options to be utilized, including rail and barge transport, if feasible, in combination with other transportation methods necessary to meet the closure timeframe established in subsection C, and (ii) plans for any transportation by truck, including the frequency of truck travel, the route of truck travel, and measures to control noise, traffic impact, safety, and fugitive dust caused by such truck travel. Once such transportation plan is completed, the owner or operator shall post it on a publicly accessible website. The owner or operator shall provide notice of the availability of the plan to the Department and the chief administrative officers of the consulting localities and shall publish such notice once in a newspaper of general circulation in such locality.

E. The owner or operator of any CCR unit subject to the provisions of subsection B shall accept and review proposals to beneficially reuse any CCR that are not subject to an existing contractual agreement to remove CCR pursuant to the provisions of subsection B every four years beginning July 1, 2022. Any entity submitting such a proposal shall provide information from which the owner or operator can determine (i) the amount of CCR that will be utilized for encapsulated beneficial use; (ii) the cost of such beneficial reuse of such CCR; and (iii) the guaranteed timeframe in which the CCR will be utilized.

F. In conducting closure activities described in subsection B, the owner or operator shall (i) identify options for utilizing local workers, (ii) consult with the Commonwealth's Chief Workforce Development Officer on opportunities to advance the Commonwealth's workforce goals, including furtherance of apprenticeship and other workforce training programs to develop the local workforce, and (iii) give priority to the hiring of local workers.

G. No later than October 1, 2022, and no less frequently than every two years thereafter until closure of all of its CCR units is complete, the owner or operator of any CCR unit subject to the provisions of subsection B shall compile the following two reports:

1. A report describing the owner's or operator's closure plan for all such CCR units; the closure progress to date, both per unit and in total; a detailed accounting of the amounts of CCR that have been and are expected to be beneficially reused from such units, both per unit and in total; a detailed accounting of the amounts of CCR that have been and are expected to be landfilled from such units, both per unit and in total; a detailed accounting of the utilization of transportation options and a transportation plan as required by subsection D; and a discussion of groundwater and surface water monitoring results and any measures taken to address such results as closure is being completed.

2. A report that contains the proposals and analysis for proposals required by subsection E.

The owner or operator shall post each such report on a publicly accessible website and shall submit each such report to the Governor, the Secretary of Natural and Historic Resources, the Chairman of the Senate Committee on Agriculture, Conservation and Natural Resources, the Chairman of the House Committee on Agriculture, Chesapeake and Natural Resources, the Chairman of the Senate Committee on Commerce and Labor, the Chairman of the House Committee on Labor and Commerce, and the Director.

H. All costs associated with closure of a CCR unit in accordance with this section shall be recoverable through a rate adjustment clause authorized by the State Corporation Commission (the Commission) under the provisions of subdivision A 5 e of § 56-585.1, provided that (i) when determining the reasonableness of such costs the Commission shall not consider closure in place of the CCR unit as an option; (ii) the annual revenue requirement recoverable through a rate adjustment clause authorized under this section, exclusive of any other rate adjustment clauses approved by the Commission under the provisions of subdivision A 5 e of §56-585.1, shall not exceed $225 million on a Virginia jurisdictional basis for the Commonwealth in any 12-month period, provided that any under-recovery amount of revenue requirements incurred in excess of $225 million in a given 12-month period, limited to the under-recovery amount and the carrying cost, shall be deferred and recovered through the rate adjustment clause over up to three succeeding 12-month periods without regard to this limitation, and with the length of the amortization period being determined by the Commission; (iii) costs may begin accruing on July 1, 2019, but no approved rate adjustment clause charges shall be included in customer bills until July 1, 2021; (iv) any such costs shall be allocated to all customers of the utility in the Commonwealth as a non-bypassable charge, irrespective of the generation supplier of any such customer; and (v) any such costs that are allocated to the utility's system customers outside of the Commonwealth that are not actually recovered from such customers shall be included for cost recovery from jurisdictional customers in the Commonwealth through the rate adjustment clause.

I. Any electric public utility subject to the requirements of this section may, without regard for whether it has petitioned for any rate adjustment clause pursuant to subdivision A 5 e of §56-585.1, petition the Commission for approval of a plan for CCR unit closure at any or all of its CCR unit sites listed in subsection B. Any such plan shall take into account site-specific conditions and shall include proposals to beneficially reuse no less than 6.8 million cubic yards of CCR in aggregate from no fewer than two of the sites listed in subsection B. The Commission shall issue its final order with regard to any such petition within six months of its filing, and in doing so shall determine whether the utility's plan for CCR unit closure, and the projected costs associated therewith, are reasonable and prudent, taking into account that closure in place of any CCR unit is not to be considered as an option. The Commission shall not consider plans that do not comply with subsection B.

J. I. Nothing in this section shall be construed to require additional beneficial reuse of CCR at any active coal-fired electric generation facility if such additional beneficial reuse results in a net increase in truck traffic on the public roads of the locality in which the facility is located as compared to such traffic during calendar year 2018.

K. J. The Commonwealth shall not authorize any cost recovery by an owner or operator subject to the provisions of this section for any fines or civil penalties resulting from violations of federal and state law or regulation.

§10.1-1402.04. Closure of certain coal combustion residuals units; Giles and Russell Counties.

A. For the purposes of this section:

"Carrying cost" means the cost associated with financing expenditures incurred but not yet recovered from the electric utility's customers and shall be calculated by applying the electric utility's weighted average cost of debt and equity capital, as determined by the State Corporation Commission, with no additional margin or profit, to any unrecovered balances.

"CCR landfill" means an area of land or an excavation that receives CCR and is not a surface impoundment, underground injection well, salt dome formation, salt bed formation, underground or surface coal mine, or cave and that is owned or operated by an electric utility.

"CCR surface impoundment" means a natural topographic depression, man-made excavation, or diked area that (i) is designed to hold an accumulation of CCR and liquids; (ii) treats, stores, or disposes of CCR; and (iii) is owned or operated by an electric utility.

"CCR unit" means any CCR landfill, CCR surface impoundment, lateral expansion of a CCR unit, or combination of two or more such units that is owned by an electric utility. Notwithstanding the provisions of 40 C.F.R. Part 257, "CCR unit" also includes any CCR below the unit boundary of the CCR landfill or CCR surface impoundment.

"Coal combustion residuals" or "CCR" means fly ash, bottom ash, boiler slag, and flue gas desulfurization materials generated from burning coal for the purpose of generating electricity by an electric utility.

"Commission" means the State Corporation Commission.

"Encapsulated beneficial use" means a beneficial use of CCR that binds the CCR into a solid matrix and minimizes its mobilization into the surrounding environment.

The definitions in this subsection shall be interpreted in a manner consistent with 40 C.F.R. Part 257, except as expressly provided in this section.

B. The owner or operator of any CCR unit located in Giles County or Russell County at the Glen Lyn Plant and the Clinch River Plant shall, if all CCR units at such plant ceased receiving CCR and submitted notification of completion of a final cap to the Department prior to January 1, 2019, complete post-closure care and any required corrective action of such unit. If all CCR units at such plant have not submitted notification of completion of a final cap to the Department prior to January 1, 2019, the owner or operator shall close all CCR units at such plant by (i) removing all of the CCR in accordance with applicable standards established by Virginia Solid Waste Management Regulations (9VAC20-81) and (ii) either (a) beneficially reusing all such CCR in a recycling process for encapsulated beneficial use or (b) disposing of the CCR in a permitted landfill on the property upon which the CCR unit is located, adjacent to the property upon which the CCR unit is located, or off of the property on which the CCR unit is located, that includes, at a minimum, a composite liner and leachate collection system that meets or exceeds the federal Criteria for Municipal Solid Waste Landfills pursuant to 40 C.F.R. Part 258. The owner or operator shall beneficially reuse CCR removed from its CCR unit if beneficial use of such removed CCR is anticipated to reduce costs incurred under this section.

C. The owner or operator shall complete the closure of any such CCR unit required by this section no later than 15 years after initiating the excavation process at that CCR unit. During the closure process, the owner or operator shall, at its expense, offer to provide a connection to a municipal water supply, or where such connection is not feasible provide water testing, for any residence within one-half mile of the CCR unit.

D. Where closure pursuant to this section requires that CCR that has been beneficially reused be removed off-site, the owner or operator shall develop a transportation plan in consultation with any county, city, or town in which the CCR units are located and any county, city, or town within two miles of the CCR units that minimizes the impact of any transport of CCR on adjacent property owners and surrounding communities. The transportation plan shall include (i) alternative transportation options to be utilized, including rail and barge transport, if feasible, in combination with other transportation methods necessary to meet the closure timeframe established in subsection C and (ii) plans for any transportation by truck, including the frequency of truck travel, the route of truck travel, and measures to control noise, traffic impact, safety, and fugitive dust caused by such truck travel. Once such transportation plan is completed, the owner or operator shall post it on a publicly accessible website. The owner or operator shall provide notice of the availability of the plan to the Department and the chief administrative officers of the consulting localities and shall publish such notice once in a newspaper of general circulation in such locality.

E. The owner or operator of any CCR unit subject to the provisions of subsection B shall accept and review proposals for the encapsulated beneficial use of CCR pursuant to the provisions of subsection B every four years beginning July 1, 2023. Any entity submitting such a proposal shall provide information from which the owner or operator can determine (i) the amount of CCR that will be utilized for encapsulated beneficial use; (ii) the cost of the proposed beneficial use of such CCR; and (iii) the guaranteed timeframe in which the CCR will be utilized.

F. In conducting closure activities described in subsection B, the owner or operator shall (i) identify options for utilizing local workers; (ii) consult with the Commonwealth's Chief Workforce Development Officer on opportunities to advance the Commonwealth's workforce goals, including furtherance of apprenticeship and other workforce training programs to develop the local workforce; and (iii) give priority to the hiring of local workers.

G. No later than October 1, 2023, and no less frequently than every two years thereafter until closure of or corrective action at all of its CCR units is complete, the owner or operator of any CCR unit subject to the provisions of subsection B shall compile the following two reports:

1. A report describing the owner's or operator's closure plan for all such CCR units; the closure progress to date, both per unit and in total; a detailed accounting of the amounts of CCR that have been and are expected to be beneficially reused from such units, both per unit and in total; a detailed accounting of the amounts of CCR that have been and are expected to be landfilled from such units, both per unit and in total; a detailed accounting of the utilization of transportation options and a transportation plan as required by subsection D; and a discussion of groundwater and surface water monitoring results and any corrective actions or other measures taken to address such results as closure is being completed.

2. A report that contains the proposals and analysis for proposals required by subsection E.

The owner or operator shall post each such report on a publicly accessible website and shall submit each such report to the Governor, the Secretary of Natural and Historic Resources, the Chairman of the Senate Committee on Agriculture, Conservation and Natural Resources, the Chairman of the House Committee on Agriculture, Chesapeake and Natural Resources, the Chairman of the Senate Committee on Commerce and Labor, the Chairman of the House Committee on Labor and Commerce, and the Director.

H. All costs associated with closure by removal of a CCR unit or encapsulated beneficial use of CCR material in accordance with subsection B shall be recoverable through a rate adjustment clause authorized by the Commission under the provisions of subdivision A 5 e of §56-585.1, provided that (i) when determining the reasonableness of such costs the Commission shall not consider closure in place of the CCR unit as an option; (ii) the annual revenue requirement recoverable through a rate adjustment clause authorized under this section, exclusive of any other rate adjustment clauses approved by the Commission under the provisions of subdivision A 5 e of §56-585.1, shall not exceed $40 million on a Virginia jurisdictional basis for the Commonwealth in any 12-month period, provided that any under-recovery amount of revenue requirements incurred in excess of $40 million in a given 12-month period, limited to the under-recovery amount and the carrying cost, shall be deferred and recovered through the rate adjustment clause over up to three succeeding 12-month periods without regard to this limitation, and with the length of the amortization period being determined by the Commission; (iii) costs may begin accruing on July 1, 2020, but no approved rate adjustment clause charges shall be included in customer bills until July 1, 2022; (iv) any such costs shall be allocated to all customers of the utility in the Commonwealth as a non-bypassable charge, irrespective of the generation supplier of any such customer; and (v) any such costs that are allocated to the utility's system customers outside of the Commonwealth that are not actually recovered from such customers shall be included for cost recovery from jurisdictional customers in the Commonwealth through the rate adjustment clause.

I. Any electric public utility subject to the requirements of this section may, without regard for whether it has petitioned for any rate adjustment clause pursuant to subdivision A 5 e of §56-585.1, petition the Commission for approval of a plan for CCR unit closure at any or all of its CCR unit sites listed in subsection B. Any such plan shall take into account site-specific conditions and shall include proposals to beneficially reuse CCR from the sites if beneficial use is anticipated to reduce the costs allocated to customers. The Commission shall issue its final order with regard to any such petition within six months of its filing, and in doing so shall determine whether the utility's plan for CCR unit closure, and the projected costs associated therewith, are reasonable and prudent, taking into account that closure in place of any CCR unit is not to be considered as an option. The Commission shall not consider plans that do not comply with subsection B.

J. I. Nothing in this section shall be construed to require additional beneficial reuse of CCR at any active coal-fired electric generation facility if such additional beneficial reuse results in a net increase in truck traffic on the public roads of the locality in which the facility is located as compared with such traffic during calendar year 2019.

K. J. The Commonwealth shall not authorize any cost recovery by an owner or operator subject to the provisions of this section for any fines or civil penalties resulting from violations of federal and state law or regulation.

§45.2-1701.1. Public disclosure of certain electric generating facility closures.

A. The provisions of this section shall apply to any electric generating facility that:

1. Has a nameplate generating capacity of 80 megawatts or more;

2. Is located in the Commonwealth;

3. Emits carbon dioxide as a byproduct of combusting fuel, whether or not certificated by the State Corporation Commission pursuant to subsection D of §56-580; and

4. Is subject to, and not exempt from, regulations adopted pursuant to subsection E of §10.1-1308 or §10.1-1330.

B. Within 30 days of an owner of an electric generating facility making public the decision to close such facility, or within 30 days of the owner of an electric generating facility making a filing with the U.S. Securities and Exchange Commission regarding a material impact to the cost, operations, or financial condition of the owner, which material impact is a direct precursor to the closure of the electric generating facility, the owner shall send a written notice of the impending closure to:

1. The governing body of the locality where the facility is located;

2. The governing body of any locality adjoining the locality where the facility is located;

3. Any town council located within a county described in subdivision 1;

4. Any planning district commission of any locality described in subdivision 1 or 2;

5. The State Corporation Commission Division of Public Utility Regulation;

6. The Department and the Division;

7. The Department of Housing and Community Development;

8. PJM Interconnection, LLC;

9. The Virginia Employment Commission;

10. The Department of Environmental Quality; and

11. The Virginia Council on Environmental Justice.

C. The notice required by subsection B shall include, at a minimum, (i) the anticipated closure date of the facility; (ii) references to any website maintained by the owner containing closure information; (iii) a list of permits obtained from a local government, the State Air Pollution Control Board, the State Water Control Board, or the Department of Environmental Quality, including the permit number and date of issuance; (iv) anticipated future use of the facility site, if known; (v) workforce transition assistance information; and (vi) decommissioning information. If the owner of the facility is a registrant with the U.S. Securities and Exchange Commission, any filings mentioning the impending closure shall also be included with the notice.

D. In the six months following receipt of the notice required by subsection B, the governing body of the locality where the facility is located shall conduct at least three public hearings, which may be part of a regular meeting agenda, where at least one representative of the owner of the facility being closed shall be present, make a presentation regarding the impending closure, and take questions from the governing body and the public.

E. In the six months following receipt of the notice required by subsection B, the planning district commission of the locality where the facility is located shall conduct at least one public hearing, which may be part of a regular meeting agenda, where at least one representative of the owner of the facility being closed shall be present, make a presentation regarding the impending closure, and take questions from the planning district commission and the public.

F. The Division shall maintain a public website listing the facilities subject to this section and their anticipated closure dates, if such dates are reasonably known by virtue of the laws of the Commonwealth or a public record or filing with an agency of the Commonwealth, including the State Corporation Commission, and a link shall be provided to the facilities' environmental protection or remediation obligations included in permits obtained from the Department, State Air Pollution Control Board, State Water Control Board, Department of Environmental Quality, or local governing body. At least every 12 months, the State Corporation Commission shall transmit to the Division any information that it reasonably believes would necessitate updates to the anticipated closure dates or other information contained on the Division's website.

G. As providing advance notice to affected communities of an impending closure of a facility under this section is a matter of vital importance for public policy, this section shall be liberally construed. The obligations imposed on agencies of the Commonwealth under this section are to be construed in favor of public disclosure of the information required by subsection F.

H. Notwithstanding the provisions of subsection A, the provisions of this section shall not apply to any electric generating facility that has a nameplate generating capacity of 90 megawatts or less and that filed a deactivation notice with PJM Interconnection, LLC, prior to September 1, 2019.

§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 biennial basis commencing in 2023, with such proceedings utilizing the two successive 12-month test periods ending December 31 immediately preceding the year in which such review proceeding is conducted. For purposes of this section, a Phase I Utility is an investor-owned incumbent electric utility that was, as of July 1, 1999, not bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002, and a Phase II Utility is an investor-owned incumbent electric utility that was bound by such a settlement.

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

a. The Commission may use any methodology to determine such return it finds consistent with the public interest. However, for a Phase I Utility, for applications received by the Commission on or after January 1, 2020, such return shall not be set lower than the average of either (i) the returns on common equity reported to the Securities and Exchange Commission for the three most recent annual periods for which such data are available by not less than a majority, selected by the Commission as specified in subdivision 2 b, of other investor-owned electric utilities in the peer group of the utility subject to such triennial review or (ii) the authorized returns on common equity that are set by the applicable regulatory commissions for the same selected peer group, nor shall the Commission set such return more than 150 basis points higher than such average.

b. For a Phase I Utility, in selecting such majority of peer group investor-owned electric utilities for applications received by the Commission on or after January 1, 2020, the Commission shall first remove from such group the two utilities within such group that have the lowest reported or authorized, as applicable, returns of the group, as well as the two utilities within such group that have the highest reported or authorized, as applicable, returns of the group, and the Commission shall then select a majority of the utilities remaining in such peer group. In its final order regarding such triennial review, the Commission shall identify the utilities in such peer group it selected for the calculation of such limitation. With respect to a Phase I Utility, for purposes of this subdivision 2, an investor-owned electric utility shall be deemed part of such peer group if (i) its principal operations are conducted in the southeastern United States east of the Mississippi River in either the states of West Virginia or Kentucky or in those states south of Virginia, excluding the state of Tennessee, (ii) it is a vertically-integrated electric utility providing generation, transmission, and distribution services whose facilities and operations are subject to state public utility regulation in the state where its principal operations are conducted, (iii) it had a long-term bond rating assigned by Moody's Investors Service of at least Baa at the end of the most recent test period subject to such review, and (iv) it is not an affiliate of the utility subject to such review or a utility whose fair rate of return on common equity is determined by the Commission.

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

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

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

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

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

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

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

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

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

3. Each such utility shall make a triennial filing by March 31 of every third year, with such filings commencing for a Phase I Utility in 2020, and such filings commencing for a Phase II Utility in 2021 and terminating thereafter. Such filing shall encompass the three successive 12-month test periods ending December 31 immediately preceding the year in which such proceeding is conducted, except that the filing for a Phase II Utility in 2021 shall encompass the four successive 12-month test periods ending December 31, 2020. After 2021, each Phase II Utility shall make a biennial filing by March 31 of every second year, except that the 2023 filing for a Phase II Utility shall be made on or after July 1, 2023. All biennial filings shall encompass the two successive 12-month test periods ending December 31 immediately preceding the year in which such review proceeding is conducted. All such filings shall consist of the schedules contained in the Commission's rules governing utility rate increase applications, and in every such case the filing for each year shall be identified separately and shall be segregated from any other year encompassed by the filing. In a filing under this subdivision that does not result in an overall rate change, a utility may propose an adjustment to one or more tariffs that are revenue neutral to the utility.

If the Commission determines that rates should be revised or credits be applied to customers' bills pursuant to subdivision 8 or 10, any rate adjustment clauses previously implemented related to facilities utilizing simple-cycle combustion turbines described in subdivision 6, shall be combined with the utility's costs, revenues, and investments until the amounts that are the subject of such rate adjustment clauses are fully recovered. The Commission shall combine such clauses with the utility's costs, revenues, and investments only after it makes its initial determination with regard to necessary rate revisions or credits to customers' bills, and the amounts thereof, but after such clauses are combined as specified in this paragraph, they shall thereafter be considered part of the utility's costs, revenues, and investments for the purposes of future review proceedings.

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

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

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

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

b. Projected and actual costs for the utility to design and operate fair and effective peak-shaving programs or pilot programs. The Commission shall approve such a petition if it finds that the program is in the public interest, provided that the Commission shall allow the recovery of such costs as it finds are reasonable;

c. Projected and actual costs for the utility to design, implement, and operate energy efficiency programs or pilot programs. Any such petition shall include a proposed budget for the design, implementation, and operation of the energy efficiency program, including anticipated savings from and spending on each program, and the Commission shall grant a final order on such petitions within eight months of initial filing. The Commission shall only approve such a petition if it finds that the program is in the public interest. If the Commission determines that an energy efficiency program or portfolio of programs is not in the public interest, its final order shall include all work product and analysis conducted by the Commission's staff in relation to that program that has bearing upon the Commission's determination. Such order shall adhere to existing protocols for extraordinarily sensitive information.

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

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

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

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

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

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

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

A utility shall not charge such large general service customer for the costs of installing energy efficiency equipment beyond what is required to provide electric service and meter such service on the customer's premises if the customer provides, at the customer's expense, equivalent energy efficiency equipment. In all relevant proceedings pursuant to this section, the Commission shall take into consideration the goals of economic development, energy efficiency and environmental protection in the Commonwealth;

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

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

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

Any rate adjustment clause approved under subdivision 5 c by the Commission shall remain in effect until the utility exhausts the approved budget for the energy efficiency program. The Commission shall have the authority to determine the duration or amortization period for any other rate adjustment clause approved under this subdivision.

6. To ensure the generation and delivery of a reliable and adequate supply of electricity, to meet the utility's projected native load obligations and to promote economic development, a utility may at any time, after the expiration or termination of capped rates, petition the Commission for approval of a rate adjustment clause for recovery on a timely and current basis from customers of the costs of (i) a coal-fueled generation facility that utilizes Virginia coal and is located in the coalfield region of the Commonwealth as described in §15.2-6002, regardless of whether such facility is located within or without the utility's service territory, (ii) one or more other generation facilities, (iii) one or more major unit modifications of generation facilities, including the costs of any system or equipment upgrade, system or equipment replacement, or other cost reasonably appropriate to extend the combined operating license for or the operating life of one or more generation facilities utilizing nuclear power, (iv) one or more new underground facilities to replace one or more existing overhead distribution facilities of 69 kilovolts or less located within the Commonwealth, (v) one or more pumped hydroelectricity generation and storage facilities that utilize on-site or off-site renewable energy resources as all or a portion of their power source and such facilities and associated resources are located in the coalfield region of the Commonwealth as described in §15.2-6002, regardless of whether such facility is located within or without the utility's service territory, or (vi) one or more electric distribution grid transformation projects; however, subject to the provisions of the following sentence, the utility shall not file a petition under clause (iv) more often than annually and, in such petition, shall not seek any annual incremental increase in the level of investments associated with such a petition that exceeds five percent of such utility's distribution rate base, as such rate base was determined for the most recently ended 12-month test period in the utility's latest review proceeding conducted pursuant to subdivision 3 and concluded by final order of the Commission prior to the date of filing of such petition under clause (iv). In all proceedings regarding petitions filed under clause (iv) or (vi), the level of investments approved for recovery in such proceedings shall be in addition to, and not in lieu of, levels of investments previously approved for recovery in prior proceedings under clause (iv) or (vi), as applicable. As of December 1, 2028, any costs recovered by a utility pursuant to clause (iv) shall be limited to any remaining costs associated with conversions of overhead distribution facilities to underground facilities that have been previously approved or are pending approval by the Commission through a petition by the utility under this subdivision. Such a petition concerning facilities described in clause (ii) that utilize nuclear power, facilities described in clause (ii) that are coal-fueled and will be built by a Phase I Utility, or facilities described in clause (i) may also be filed before the expiration or termination of capped rates. A utility that constructs or makes modifications to any such facility, or purchases any facility consisting of at least one megawatt of generating capacity using energy derived from sunlight and located in the Commonwealth and that utilizes goods or services sourced, in whole or in part, from one or more Virginia businesses, shall have the right to recover the costs of the facility, as accrued against income, through its rates, including projected construction work in progress, and any associated allowance for funds used during construction, planning, development and construction or acquisition costs, life-cycle costs, costs related to assessing the feasibility of potential sites for new underground facilities, and costs of infrastructure associated therewith, plus, as an incentive to undertake such projects, an enhanced rate of return on common equity calculated as specified below; however, in determining the amounts recoverable under a rate adjustment clause for new underground facilities, the Commission shall not consider, or increase or reduce such amounts recoverable because of (a) the operation and maintenance costs attributable to either the overhead distribution facilities being replaced or the new underground facilities or (b) any other costs attributable to the overhead distribution facilities being replaced. Notwithstanding the preceding sentence, the costs described in clauses (a) and (b) thereof shall remain eligible for recovery from customers through the utility's base rates for distribution service. A utility filing a petition for approval to construct or purchase a facility consisting of at least one megawatt of generating capacity using energy derived from sunlight and located in the Commonwealth and that utilizes goods or services sourced, in whole or in part, from one or more Virginia businesses may propose a rate adjustment clause based on a market index in lieu of a cost of service model for such facility. A utility seeking approval to construct or purchase a generating facility that emits carbon dioxide shall demonstrate that it has already met the energy savings goals identified in §56-596.2 and that the identified need cannot be met more affordably through the deployment or utilization of demand-side resources or energy storage resources and that it has considered and weighed alternative options, including third-party market alternatives, in its selection process.

The costs of the facility, other than return on projected construction work in progress and allowance for funds used during construction, shall not be recovered prior to the date a facility constructed by the utility and described in clause (i), (ii), (iii), or (v) begins commercial operation, the date the utility becomes the owner of a purchased generation facility consisting of at least one megawatt of generating capacity using energy derived from sunlight and located in the Commonwealth and that utilizes goods or services sourced, in whole or in part, from one or more Virginia businesses, or the date new underground facilities are classified by the utility as plant in service. In any application to construct a new generating facility, the utility shall include, and the Commission shall consider, the social cost of carbon, as determined by the Commission, as a benefit or cost, whichever is appropriate. The Commission shall ensure that the development of new, or expansion of existing, energy resources or facilities does not have a disproportionate adverse impact on historically economically disadvantaged communities. The Commission may adopt any rules it deems necessary to determine the social cost of carbon and shall use the best available science and technology, including the Technical Support Document: Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866, published by the Interagency Working Group on Social Cost of Greenhouse Gases from the United States Government in August 2016, as guidance. The Commission shall include a system to adjust the costs established in this section with inflation.

Such enhanced rate of return on common equity shall be applied to allowance for funds used during construction and to construction work in progress during the construction phase of the facility and shall thereafter be applied to the entire facility during the first portion of the service life of the facility. The first portion of the service life shall be as specified in the table below; however, the Commission shall determine the duration of the first portion of the service life of any facility, within the range specified in the table below, which determination shall be consistent with the public interest and shall reflect the Commission's determinations regarding how critical the facility may be in meeting the energy needs of the citizens of the Commonwealth and the risks involved in the development of the facility. After the first portion of the service life of the facility is concluded, the utility's general rate of return shall be applied to such facility for the remainder of its service life. As used herein, the service life of the facility shall be deemed to begin on the date a facility constructed by the utility and described in clause (i), (ii), (iii), or (v) begins commercial operation, the date the utility becomes the owner of a purchased generation facility consisting of at least one megawatt of generating capacity using energy derived from sunlight and located in the Commonwealth and that utilizes goods or services sourced, in whole or in part, from one or more Virginia businesses, or the date new underground facilities or new electric distribution grid transformation projects are classified by the utility as plant in service, and such service life shall be deemed equal in years to the life of that facility as used to calculate the utility's depreciation expense. Such enhanced rate of return on common equity shall be calculated by adding the basis points specified in the table below to the utility's general rate of return, and such enhanced rate of return shall apply only to the facility that is the subject of such rate adjustment clause. Allowance for funds used during construction shall be calculated for any such facility utilizing the utility's actual capital structure and overall cost of capital, including an enhanced rate of return on common equity as determined pursuant to this subdivision, until such construction work in progress is included in rates. The construction of any facility described in clause (i) or (v) is in the public interest, and in determining whether to approve such facility, the Commission shall liberally construe the provisions of this title. The construction or purchase by a utility of one or more generation facilities with at least one megawatt of generating capacity, and with an aggregate rated capacity that does not exceed 16,100 megawatts, including rooftop solar installations with a capacity of not less than 50 kilowatts, and with an aggregate capacity of 100 megawatts, that use energy derived from sunlight or from onshore wind and are located in the Commonwealth or off the Commonwealth's Atlantic shoreline, regardless of whether any of such facilities are located within or without the utility's service territory, is in the public interest, and in determining whether to approve such facility, the Commission shall liberally construe the provisions of this title. A utility may enter into short-term or long-term power purchase contracts for the power derived from sunlight generated by such generation facility prior to purchasing the generation facility. The replacement of any subset of a utility's existing overhead distribution tap lines that have, in the aggregate, an average of nine or more total unplanned outage events-per-mile over a preceding 10-year period with new underground facilities in order to improve electric service reliability is in the public interest. In determining whether to approve petitions for rate adjustment clauses for such new underground facilities that meet this criteria, and in determining the level of costs to be recovered thereunder, the Commission shall liberally construe the provisions of this title.

The conversion of any such facilities on or after September 1, 2016, is deemed to provide local and system-wide benefits and to be cost beneficial, and the costs associated with such new underground facilities are deemed to be reasonably and prudently incurred and, notwithstanding the provisions of subsection C or D, shall be approved for recovery by the Commission pursuant to this subdivision, provided that the total costs associated with the replacement of any subset of existing overhead distribution tap lines proposed by the utility with new underground facilities, exclusive of financing costs, shall not exceed an average cost per customer of $20,000, with such customers, including those served directly by or downline of the tap lines proposed for conversion, and, further, such total costs shall not exceed an average cost per mile of tap lines converted, exclusive of financing costs, of $750,000. A utility shall, without regard for whether it has petitioned for any rate adjustment clause pursuant to clause (vi), petition the Commission, not more than once annually, for approval of a plan for electric distribution grid transformation projects. Any plan for electric distribution grid transformation projects shall include both measures to facilitate integration of distributed energy resources and measures to enhance physical electric distribution grid reliability and security. In ruling upon such a petition, the Commission shall consider whether the utility's plan for such projects, and the projected costs associated therewith, are reasonable and prudent. Such petition shall be considered on a stand-alone basis without regard to the other costs, revenues, investments, or earnings of the utility; without regard to whether the costs associated with such projects will be recovered through a rate adjustment clause under this subdivision or through the utility's rates for generation and distribution services; and without regard to whether such costs will be the subject of a customer credit offset, as applicable, pursuant to subdivision 8 d. The Commission's final order regarding any such petition for approval of an electric distribution grid transformation plan shall be entered by the Commission not more than six months after the date of filing such petition. The Commission shall likewise enter its final order with respect to any petition by a utility for a certificate to construct and operate a generating facility or facilities utilizing energy derived from sunlight, pursuant to subsection D of §56-580, within six months after the date of filing such petition. The basis points to be added to the utility's general rate of return to calculate the enhanced rate of return on common equity, and the first portion of that facility's service life to which such enhanced rate of return shall be applied, shall vary by type of facility, as specified in the following table:

Only those facilities as to which a rate adjustment clause under this subdivision has been previously approved by the Commission, or as to which a petition for approval of such rate adjustment clause was filed with the Commission, on or before January 1, 2013, shall be entitled to the enhanced rate of return on common equity as specified in the above table during the construction phase of the facility and the approved first portion of its service life.

Thirty percent of all costs of such a facility utilizing nuclear power that the utility incurred between July 1, 2007, and December 31, 2013, and all of such costs incurred after December 31, 2013, may be deferred by the utility and recovered through a rate adjustment clause under this subdivision at such time as the Commission provides in an order approving such a rate adjustment clause. The remaining 70 percent of all costs of such a facility that the utility incurred between July 1, 2007, and December 31, 2013, shall not be deferred for recovery through a rate adjustment clause under this subdivision; however, such remaining 70 percent of all costs shall be recovered ratably through existing base rates as determined by the Commission in the test periods under review in the utility's next review filed after July 1, 2014. Thirty percent of all costs of a facility utilizing energy derived from offshore wind that the utility incurred between July 1, 2007, and December 31, 2013, and all of such costs incurred after December 31, 2013, may be deferred by the utility and recovered through a rate adjustment clause under this subdivision at such time as the Commission provides in an order approving such a rate adjustment clause. The remaining 70 percent of all costs of such a facility that the utility incurred between July 1, 2007, and December 31, 2013, shall not be deferred for recovery through a rate adjustment clause under this subdivision; however, such remaining 70 percent of all costs shall be recovered ratably through existing base rates as determined by the Commission in the test periods under review in the utility's next review filed after July 1, 2014.

In connection with planning to meet forecasted demand for electric generation supply and assure the adequate and sufficient reliability of service, consistent with §56-598, planning and development activities for a new utility-owned and utility-operated generating nuclear generation facility or facilities utilizing energy derived from sunlight or from onshore or offshore wind are in the public interest.

Notwithstanding any provision of Chapter 296 of the Acts of Assembly of 2018, construction, purchasing, or leasing activities for a new utility-owned and utility-operated generating facility or facilities utilizing energy derived from sunlight or from onshore wind with an aggregate capacity of 16,100 megawatts, including rooftop solar installations with a capacity of not less than 50 kilowatts, and with an aggregate capacity of 100 megawatts, together with a utility-owned and utility-operated generating facility or facilities utilizing energy derived from offshore wind with an aggregate capacity of not more than 3,000 megawatts, are in the public interest. Additionally, energy storage facilities with an aggregate capacity of 2,700 megawatts are in the public interest. To the extent that a utility elects to recover the costs of any such new generation or energy storage facility or facilities through its rates for generation and distribution services and does not petition and receive approval from the Commission for recovery of such costs through a rate adjustment clause described in clause (ii), the Commission shall, upon the request of the utility in a review proceeding, provide for a customer credit reinvestment offset, as applicable, pursuant to subdivision 8 d with respect to all costs deemed reasonable and prudent by the Commission in a proceeding pursuant to subsection D of §56-580 or in a review proceeding.

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

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

As used in this subdivision, a generation facility is (1) "coalbed methane gas powered" if the facility is fired at least 50 percent by coalbed methane gas, as such term is defined in §45.2-1600, produced from wells located in the Commonwealth, and (2) "landfill gas powered" if the facility is fired by methane or other combustible gas produced by the anaerobic digestion or decomposition of biodegradable materials in a solid waste management facility licensed by the Waste Management Board. A landfill gas powered facility includes, in addition to the generation facility itself, the equipment used in collecting, drying, treating, and compressing the landfill gas and in transmitting the landfill gas from the solid waste management facility where it is collected to the generation facility where it is combusted.

For purposes of this subdivision, "general rate of return" means the fair combined rate of return on common equity as it is determined by the Commission for such utility pursuant to subdivision 2.

Notwithstanding any other provision of this subdivision, if the Commission finds during the triennial review conducted for a Phase II Utility in 2021 that such utility has not filed applications for all necessary federal and state regulatory approvals to construct one or more nuclear-powered or coal-fueled generation facilities that would add a total capacity of at least 1500 megawatts to the amount of the utility's generating resources as such resources existed on July 1, 2007, or that, if all such approvals have been received, that the utility has not made reasonable and good faith efforts to construct one or more such facilities that will provide such additional total capacity within a reasonable time after obtaining such approvals, then the Commission, if it finds it in the public interest, may reduce on a prospective basis any enhanced rate of return on common equity previously applied to any such facility to no less than the general rate of return for such utility and may apply no less than the utility's general rate of return to any such facility for which the utility seeks approval in the future under this subdivision.

Notwithstanding any other provision of this subdivision, if a Phase II utility obtains approval from the Commission of a rate adjustment clause pursuant to subdivision 6 associated with a test or demonstration project involving a generation facility utilizing energy from offshore wind, and such utility has not, as of July 1, 2023, commenced construction as defined for federal income tax purposes of an offshore wind generation facility or facilities with a minimum aggregate capacity of 250 megawatts, then the Commission, if it finds it in the public interest, may direct that the costs associated with any such rate adjustment clause involving said test or demonstration project shall thereafter no longer be recovered through a rate adjustment clause pursuant to subdivision 6 and shall instead be recovered through the utility's rates for generation and distribution services, with no change in such rates for generation and distribution services as a result of the combination of such costs with the other costs, revenues, and investments included in the utility's rates for generation and distribution services. Any such costs shall remain combined with the utility's other costs, revenues, and investments included in its rates for generation and distribution services until such costs are fully recovered.

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

The Commission's final order regarding any petition filed pursuant to subdivision 4, 5, or 6 shall be entered not more than three months, eight months, and nine months, respectively, after the date of filing of such petition. If such petition is approved, the order shall direct that the applicable rate adjustment clause be applied to customers' bills not more than 60 days after the date of the order, or upon the expiration or termination of capped rates, whichever is later. At any time, the Commission may, in its discretion, for a Phase I Utility, upon petition by such a utility or upon its own initiated proceeding, direct the consolidation of any one or more subsets of rate adjustment clauses previously implemented pursuant to subdivision 5 or 6 in the interest of judicial economy, customer transparency, or other factors the Commission determines to be appropriate. Any subset of rate adjustment clauses so consolidated shall continue to be considered by the Commission without regard to the other costs, revenues, investments, or earnings of the utility and remain as a cost recovery mechanism independent from the utility's rates for generation and distribution services pursuant to §56-585.8 and subdivisions 5 and 6, but will be combined as a single rate adjustment clause for cost recovery and review purposes. Any rate adjustment clause or subset of rate adjustment clauses so consolidated shall be named in a manner, as determined by the Commission, that reasonably informs customers as to the nature of the costs recovered by the consolidated rate adjustment clause. At any time, the Commission may, in its discretion, for a Phase II Utility, upon petition by such a utility or upon its own initiated proceeding, direct the consolidation of any one or more subsets of rate adjustment clauses previously implemented pursuant to subdivision 5 or 6 in the interest of judicial economy, customer transparency, or other factors the Commission determines to be appropriate. Any subset of rate adjustment clauses so consolidated shall continue to be considered by the Commission without regard to the other costs, revenues, investments, or earnings of the utility and remain as a cost recovery mechanism independent from the utility's rates for generation and distribution services pursuant to this subdivision and subdivisions 5 and 6, but will be combined as a single rate adjustment clause for cost recovery and review purposes. Any rate adjustment clause or subset of rate adjustment clauses so consolidated shall be named in a manner, as determined by the Commission, that reasonably informs customers as to the nature of the costs recovered by the consolidated rate adjustment clause.

8. For a Phase I Utility in any triennial review proceeding filed on or before June 30, 2023 or for a Phase II Utility in any biennial review proceeding, for the purposes of reviewing earnings on the utility's rates for generation and distribution services, the following utility generation and distribution costs not proposed for recovery under any other subdivision of this subsection, as recorded per books by the utility for financial reporting purposes and accrued against income, shall be attributed to the test periods under review and deemed fully recovered in the period recorded: costs associated with asset impairments related to early retirement determinations made by the utility for utility generation facilities fueled by coal, natural gas, or oil or for automated meter reading electric distribution service meters; costs associated with projects necessary to comply with state or federal environmental laws, regulations, or judicial or administrative orders relating to coal combustion by-product management that the utility does not petition to recover through a rate adjustment clause pursuant to subdivision 5 e; costs associated with severe weather events; and costs associated with natural disasters. Such costs shall be deemed to have been recovered from customers through rates for generation and distribution services in effect during the test periods under review unless such costs, individually or in the aggregate, together with the utility's other costs, revenues, and investments to be recovered through rates for generation and distribution services, result in the utility's earned return on its generation and distribution services for the combined test periods under review to fall more than 50 basis points below the fair combined rate of return authorized under subdivision 2 for such periods or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, to fall more than 70 basis points below the fair combined rate of return authorized under subdivision 2 for such periods. In such cases, the Commission shall, in such review proceeding, authorize deferred recovery of such costs and allow the utility to amortize and recover such deferred costs over future periods as determined by the Commission. The aggregate amount of such deferred costs shall not exceed an amount that would, together with the utility's other costs, revenues, and investments to be recovered through rates for generation and distribution services, cause the utility's earned return on its generation and distribution services to exceed the fair rate of return authorized under subdivision 2, less 50 basis points, for the combined test periods under review or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, to exceed the fair rate of return authorized under subdivision 2 less 70 basis points. Notwithstanding the prior sentence, the aggregate amount of actual and reasonable costs associated with severe weather events eligible for such deferral shall not exceed an amount that would, together with the utility's other costs, revenues, and investments to be recovered through rates for generation and distribution services, cause the utility's earned return on its generation and distribution services to exceed the fair rate of return authorized for the combined test periods under review. For the purposes of determining any amount of costs that are associated with severe weather events, the Commission shall consider nationally recognized standards such as those published by the Institute of Electrical and Electronics Engineers (IEEE). Nothing in this section shall limit the Commission's authority, pursuant to the provisions of Chapter 10 (§56-232 et seq.), including specifically §56-235.2, following the review of combined test period earnings of the utility in a review, for normalization of nonrecurring test period costs and annualized adjustments for future costs, in determining any appropriate increase or decrease in the utility's rates for generation and distribution services pursuant to subdivision 8 a or 8 c.

If the Commission determines as a result of any triennial review initiated prior to July 1, 2023 that:

a. Revenue reductions related to energy efficiency measures or programs approved and deployed since the utility's previous triennial review have caused the utility, as verified by the Commission, during the test period or periods under review, considered as a whole, to earn more than 50 basis points below a fair combined rate of return on its generation and distribution services or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, more than 70 basis points below a fair combined rate of return on its generation and distribution services, as determined in subdivision 2, without regard to any return on common equity or other matters determined with respect to facilities described in subdivision 6, the Commission shall order increases to the utility's rates for generation and distribution services necessary to recover such revenue reductions. If the Commission finds, for reasons other than revenue reductions related to energy efficiency measures, that the utility has, during the test period or periods under review, considered as a whole, earned more than 50 basis points below a fair combined rate of return on its generation and distribution services or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, more than 70 basis points below a fair combined rate of return on its generation and distribution services, as determined in subdivision 2, without regard to any return on common equity or other matters determined with respect to facilities described in subdivision 6, the Commission shall order increases to the utility's rates necessary to provide the opportunity to fully recover the costs of providing the utility's services and to earn not less than such fair combined rate of return, using the most recently ended 12-month test period as the basis for determining the amount of the rate increase necessary. However, in the first triennial review proceeding conducted after January 1, 2021, for a Phase II Utility, the Commission may not order a rate increase, and in all triennial reviews of a Phase I or Phase II utility, the Commission may not order such rate increase unless it finds that the resulting rates are necessary to provide the utility with the opportunity to fully recover its costs of providing its services and to earn not less than a fair combined rate of return on both its generation and distribution services, as determined in subdivision 2, without regard to any return on common equity or other matters determined with respect to facilities described in subdivision 6, using the most recently ended 12-month test period as the basis for determining the permissibility of any rate increase under the standards of this sentence, and the amount thereof; and provided that, solely in connection with making its determination concerning the necessity for such a rate increase or the amount thereof, the Commission shall, in any triennial review proceeding conducted prior to July 1, 2028, exclude from this most recently ended 12-month test period any remaining investment levels associated with a prior customer credit reinvestment offset pursuant to subdivision d.

b. The utility has, during the test period or test periods under review, considered as a whole, earned more than 50 basis points above a fair combined rate of return on its generation and distribution services or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, more than 70 basis points above a fair combined rate of return on its generation and distribution services, as determined in subdivision 2, without regard to any return on common equity or other matters determined with respect to facilities described in subdivision 6, the Commission shall, subject to the provisions of subdivisions 8 d and 9, direct that 60 percent of the amount of such earnings that were more than 50 basis points, or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, that 70 percent of the amount of such earnings that were more than 70 basis points, above such fair combined rate of return for the test period or periods under review, considered as a whole, shall be credited to customers' bills. Any such credits shall be amortized over a period of six to 12 months, as determined at the discretion of the Commission, following the effective date of the Commission's order, and shall be allocated among customer classes such that the relationship between the specific customer class rates of return to the overall target rate of return will have the same relationship as the last approved allocation of revenues used to design base rates; or

c. The utility has, during the test period or test periods under review, considered as a whole, earned more than 50 basis points above a fair combined rate of return on its generation and distribution services or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, more than 70 basis points above a fair combined rate of return on its generation and distribution services, as determined in subdivision 2, without regard to any return on common equity or other matter determined with respect to facilities described in subdivision 6, and the combined aggregate level of capital investment that the Commission has approved other than those capital investments that the Commission has approved for recovery pursuant to a rate adjustment clause pursuant to subdivision 6 made by the utility during the test periods under review in that triennial review proceeding in new utility-owned generation facilities utilizing energy derived from sunlight, or from wind, and in electric distribution grid transformation projects, as determined pursuant to subdivision 8 d, does not equal or exceed 100 percent of the earnings that are more than 70 basis points above the utility's fair combined rate of return on its generation and distribution services for the combined test periods under review in that triennial review proceeding, the Commission shall, subject to the provisions of subdivision 10 and in addition to the actions authorized in subdivision b, also order reductions to the utility's rates it finds appropriate. However, in the first triennial review proceeding conducted after January 1, 2021, for a Phase II Utility, any reduction to the utility's rates ordered by the Commission pursuant to this subdivision shall not exceed $50 million in annual revenues, with any reduction allocated to the utility's rates for generation services, and in each triennial review of a Phase I or Phase II Utility, the Commission may not order such rate reduction unless it finds that the resulting rates will provide the utility with the opportunity to fully recover its costs of providing its services and to earn not less than a fair combined rate of return on its generation and distribution services, as determined in subdivision 2, without regard to any return on common equity or other matters determined with respect to facilities described in subdivision 6, using the most recently ended 12-month test period as the basis for determining the permissibility of any rate reduction under the standards of this sentence, and the amount thereof; and

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

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

9. a. In any biennial review for a Phase II Utility filed on or prior to December 31, 2023, if the Commission determines that the utility has during the test period or test periods under review, considered as a whole, earned more than 70 basis points above a fair combined rate of return on its generation and distribution services previously authorized by the Commission, as determined in subdivision 2, without regard to any return on common equity or other matters determined with respect to facilities described in subdivision 6, which have not been combined with the utility's costs, revenues, and investments for generation and distribution services, the Commission shall direct that 85 percent of the amount of such earnings that were more than 70 basis points above such fair combined rate of return for the test period or periods under review, considered as a whole, be credited to customers' bills. Any such credits shall be amortized over a period of six to 12 months, as determined at the discretion of the Commission, following the effective date of the Commission's order, and shall be allocated among customer classes such that the relationship between the specific customer class rates of return to the overall target rate of return will have the same relationship as the last approved allocation of revenues used to design base rates.

b. In any biennial review for a Phase II Utility filed on or after January 1, 2024, if the Commission determines that the utility has during the test period or test periods under review, considered as a whole, earned above its fair combined rate of return on its generation and distribution services previously authorized by the Commission, as determined in subdivision 2, without regard to any return on common equity or other matters determined with respect to facilities described in subdivision 6, which have not been combined with the utility's costs, revenues, and investments for generation and distribution services, the Commission shall direct that 85 percent of the amount of such earnings above such fair combined rate of return for the test period or periods under review, considered as a whole, be credited to customers' bills. Further, if the Commission determines that during the test period or test periods under review, considered as a whole, a Phase II Utility earned more than 150 basis points above a fair combined rate of return on its generation and distribution services previously authorized by the Commission, without regard to any return on common equity or other matters determined with respect to facilities described in subdivision 6, which have not been combined with the utility's costs, revenues, and investments for generation and distribution services, the Commission shall direct that all such earnings that were more than 150 basis points above such fair combined rate of return for the test period or periods under review, considered as a whole, be credited to customers' bills. Any such credits shall be amortized over a period of six to 12 months, as determined at the discretion of the Commission, following the effective date of the Commission's order, and shall be allocated among customer classes such that the relationship between the specific customer class rates of return to the overall target rate of return will have the same relationship as the last approved allocation of revenues used to design base rates.

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

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

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

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

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

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

D. The Commission may determine, during any proceeding authorized or required by this section, the reasonableness or prudence of any cost incurred or projected to be incurred, by a utility in connection with the subject of the proceeding. A determination of the Commission regarding the reasonableness or prudence of any such cost shall be consistent with the Commission's authority to determine the reasonableness or prudence of costs in proceedings pursuant to the provisions of Chapter 10 (§56-232 et seq.). In determining the reasonableness or prudence of a utility providing energy and capacity to its customers from renewable energy resources, the Commission shall consider the extent to which such renewable energy resources, whether utility-owned or by contract, further the objectives of the Commonwealth Clean Energy Policy set forth in §45.2-1706.1, and shall also consider whether the costs of such resources is likely to result in unreasonable increases in rates paid by customers.

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

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

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

§56-585.1:4. Development of wind generation and energy storage capacity in the Commonwealth.

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

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

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

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

E. Construction, purchasing, or leasing activities for a test or demonstration project for a new utility-owned and utility-operated generating facility or facilities utilizing energy derived from offshore wind with an aggregate capacity of not more than 16 megawatts are in the public interest.

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

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

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

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

§56-585.3. Regulation of cooperative rates after rate caps.

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

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

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

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

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

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

6. A cooperative that is not a current member of a utility aggregation cooperative may at any time petition the Commission for approval of one or more rate adjustment clauses for the timely and current recovery of cost from customers of (i) one or more generation facilities, (ii) one or more major unit modifications of generation facilities, or (iii) one or more pumped hydroelectricity generation and storage facilities. A cooperative seeking a rate adjustment clause pursuant to this subdivision shall have the right, after notice and the opportunity for a hearing, to recover the costs of a facility described in clauses (i), (ii), or (iii) in a rate adjustment clause including construction work in progress and allowance for funds during construction, planning, and development costs of infrastructure associated therewith. The costs of the facility other than projected construction work in progress and allowance for funds used during construction shall not be recovered prior to the date that the facility either (a) begins commercial operation or (b) comes under the ownership of the cooperative. For the purposes of this subdivision, the cooperative's cost of capital shall be recoverable in such a rate adjustment clause and shall be set as either the cooperative's long-term cost of debt or most recent rate of return authorized by the Commission in a rate proceeding. In any proceeding conducted pursuant to this subdivision, the Commission shall consider that all costs expended and revenues recovered arising out of the procurement of generation resources pursuant to this subdivision will inure to the benefit of the general membership of the cooperative. Nothing in this subdivision shall relieve a cooperative from any requirement to obtain a certificate of public convenience and necessity for purposes of constructing generation in the Commonwealth. The Commission's final order regarding any petition filed pursuant to this subdivision shall be entered not more than nine months after the date of filing of such petition. If such petition is approved, the order shall direct that the applicable rate adjustment clause be applied to customers' bills not more than 60 days after the date of the order. Any petition filed pursuant to this subdivision shall be considered by the Commission on a stand-alone basis without regard to the other costs, revenues, investments, or earnings of the cooperative. Any costs incurred by a cooperative prior to the filing of such petition, or during the consideration thereof by the Commission, that are proposed for recovery in such petition, shall be deferred on the books and records of the cooperative until the Commission's final order in the matter, or until the implementation of any applicable approved rate adjustment clause, whichever is later;

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

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

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

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

§56-585.8. Biennial rate reviews.

A. For the purposes of this section:

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

"Utility" means a Phase I Utility.

B. With the first review commencing on March 31, 2024, and biennially thereafter, the Commission shall conduct rate reviews of the rates, terms, and conditions for the provision of generation and distribution services by a Phase I Utility that participated in triennial review proceedings in 2020 and 2023, and such Phase I Utility shall no longer be subject to triennial review proceedings pursuant to §56-585.1.

C. In each biennial review, the Commission shall conduct a proceeding to review all rates, terms, and conditions for generation and distribution services with such proceeding utilizing the two successive 12-month test periods ending December 31 immediately preceding the year in which such proceeding is conducted. Such biennial review shall be conducted in a single, combined proceeding, except for review of the following costs, which the utility shall continue to recover and the Commission shall continue to review separately, pursuant to the applicable statutory provisions: costs that are recovered pursuant to (i) §56-249.6, (ii) subdivisions A 4, 5, and 6 of § 56-585.1, and (iii) §56-585.6.

D. Each biennial rate review proceeding shall commence on or before March 31 of the biennial review year with the filing of a petition by each Phase I Utility subject to the provisions of this section. The Commission, after providing notice and an opportunity for hearing, shall grant a final order on such petition no later than November 20. Any revisions in rates ordered by the Commission pursuant to the rate review shall take effect no later than January 1 of the subsequent year.

E. In each biennial review proceeding, the Commission shall set the fair rate of return on common equity applicable to the generation and distribution services of the utility for the two such services combined and for any rate adjustment clauses approved under subdivision A 5 or 6 of §56-585.1. The Commission may use any methodology it finds consistent with the public interest to determine the Phase I Utility's fair rate of return on common equity. The Commission may increase or decrease the combined rate of return for generation and distribution services by up to 50 basis points based on factors that may include reliability, generating plant performance, customer service, and operating efficiency of a utility. Any such adjustment to the combined rate of return for generation and distribution services shall include consideration of nationally recognized standards determined by the Commission to be appropriate for such purposes.

F. In any biennial review for a Phase I Utility, if the Commission determines in its sole discretion that the utility's existing rates for generation and distribution services will, on a going-forward basis, either produce (i) revenues in excess of the utility's authorized rate of return or (ii) revenues below the utility's authorized rate of return, then the Commission shall order any reductions or increases, as applicable and necessary, to such rates for generation and distribution services that it deems appropriate to ensure the resulting rates for generation and distribution services (a) are just and reasonable and (b) provide the utility an opportunity to recover its costs of providing services over the rate period ending on December 31 of the year of the utility's succeeding review and earn a fair rate of return authorized pursuant to this section. Such determination shall be limited to the Phase I Utility's rates for generation and distribution services and shall not consider the costs or revenues recovered in any rate adjustment clause authorized pursuant to this chapter.

G. In any biennial review of rates for generation and distribution services, if the combined rate of return on common equity earned is no more than 100 basis points above or below the fair combined rate of return, as determined by the Commission, for the test period under review, then such combined return shall not be considered either excessive or insufficient, respectively.

1. If in any biennial review, the Commission finds that, during the test period under review, considered as a whole, the utility has earned more than 100 basis points above the authorized fair combined rate of return on its generation or distribution services, the Commission shall direct that 100 percent of the amount of such earnings that were more than 100 basis points above such fair combined rate of return for the test period under review, considered as a whole, be credited to customers' bills. Any such credits shall be applied to customers' bills, as determined at the discretion of the Commission, following the effective date of the Commission's order, and shall be allocated among customer classes such that the relationship between the specific customer class rates of return to the overall target rate of return will have the same relationship as the last approved allocation of revenues used to design base rates; or

2. The Commission shall authorize deferred recovery for reasonable (i) actual costs associated with severe weather events and (ii) actual costs associated with natural disasters, not currently in rates, and the Commission shall allow the utility to amortize and recover such deferred costs over future periods as determined by the Commission. The amount of any such deferral shall not exceed an amount that would, together with the utility's other costs, revenues, and investments recovered through rates for generation and distribution services for the test period under review, cause the utility's earned return on its generation and distribution services to exceed 100 basis points above the fair combined rate of return applicable to the test period under review. For the purposes of determining any amount of costs that are associated with severe weather events, the Commission shall consider nationally recognized standards such as those published by the Institute of Electrical and Electronics Engineers (IEEE).

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

H. In any proceeding under this title, including each biennial review, to determine the prior two years' excess or deficiency for the purposes of subsection F, the Commission shall use an average rate base using the actual starting and end-of-test period capital structure of the utility, excluding any debt associated with any securitized bonds and without regard to the cost of capital, capital structure, or investments of any other entities with which the utility is affiliated. To determine a revenue requirement in any proceeding under this title, the Commission shall use the utility's actual end-of-test period capital structure and cost of capital without regard to the cost of capital, capital structure, or investments of any other entities with which the utility is affiliated, including debt associated with any securitized bonds, unless the Commission makes a finding, based on evidence in the record, that the debt to equity ratio of the actual end-of-test period capital structure of such utility is unreasonable, in which case the Commission may utilize a debt to equity ratio that it finds to be reasonable.

In a rate review for a Phase I Utility that is part of a publicly traded, consolidated group, the Commission shall determine federal and state income tax costs as follows: (i) the utility's apportioned state income tax costs shall be calculated according to the applicable statutory rate, as if the utility had not filed a consolidated return with its affiliates, and (ii) the utility's federal income tax costs shall be calculated according to the applicable federal income tax rate and shall exclude any consolidated tax liability or benefit adjustments originating from any taxable income or loss of its affiliates.

I. The Commission is authorized to determine during any biennial review the reasonableness or prudence of any cost subject to the rate review incurred or projected to be incurred by the utility, and a Phase I Utility shall recover such costs that the Commission finds to be reasonable and prudent.

J. In any biennial review conducted pursuant to this section, a Phase I Utility or any other party may propose changes to its terms and conditions and the Commission may approve, reject, or amend any changes and may propose any special rates, contracts, or incentives pursuant to §56-235.2.

K. Nothing in this section shall alter a Phase I Utility's obligations pursuant to §§56-585.5 and § 56-596.2.

L. To the extent that the provisions of this section are inconsistent with the provisions of §56-585.1, the provisions of this section shall control.

2. That §§10.1-1322.3 and 56-585.5 of the Code of Virginia are repealed.